USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 1 of 52 ORAL ARGUMENT SCHEDULED FOR FEBRUARY 25, 2015 No. 11-1302 and consolidated cases (COMPLEX) IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT EME Homer City Generation, L.P., et al., Petitioners, v. Environmental Protection Agency, et al., Respondents. On Petitions for Review of a Final Order of the United States Environmental Protection Agency STATE AND LOCAL PETITIONERS’ OPENING BRIEF ON REMAND GREG ABBOTT Attorney General of Texas BILL DAVIS Assistant Solicitor General DANIEL T. HODGE First Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL P.O. Box 12548 (MC 059) Austin, Texas 78711-2548 Tel.: (512) 936-1896 Fax: (512) 370-9191 Bill.Davis@texasattorneygeneral.gov JONATHAN F. MITCHELL Solicitor General JON NIERMANN Chief, Environmental Protection Division December 10, 2014 COUNSEL FOR THE STATE AND LOCAL PETITIONERS [Additional Counsel Listed on Signature Pages] USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 2 of 52 CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES The Court consolidated the following cases for review: 11-1302 (lead), 11-1315, 11-1323, 11-1329, 1350, 11-1357, 11-1358, 11-1359, 11-1360, 1363, 11-1364, 11-1365, 11-1366, 11-1367, 1371, 11-1372, 11-1373, 11-1374, 11-1375, 1378, 11-1379, 11-1380, 11-1381, 11-1382, 1385, 11-1386, 11-1387, 11-1388, 11-1389, 1392, 11-1393, 11-1394, and 11-1395 (A) 11-1338, 11-1361, 11-1368, 11-1376, 11-1383, 11-1390, 11-1340, 11-1362, 11-1369, 11-1377, 11-1384, 11-1391, 111111111111- Parties, Intervenors, and Amici Petitioners* AEP Texas North Co. Alabama Power Co. American Coal Co. American Energy Corp. Appalachian Power Co. ARIPPA Big Brown Lignite Company, LLC Big Brown Power Company, LLC City of Ames, Iowa City of Springfield, Illinois, Office of Public Utilities, d/b/a City Water, Light and Power Columbus Southern Power Co. Consolidated Edison Company of New York CPI USA North Carolina LLC Dairyland Power Cooperative DTE Stoneman, LLC East Kentucky Power Cooperative, Inc. EME Homer City Generation, LP Entergy Corp. * The petitioners that join this brief appear in bold. i USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 3 of 52 Environmental Committee of the Florida Electric Power Coordinating Group Environmental Energy Alliance of New York, LLC GenOn Energy, Inc. Georgia Power Co. Gulf Power Co. Indiana Michigan Power Co. International Brotherhood of Electrical Workers, AFL-CIO Kansas City Board of Public Utilities Kansas Gas and Electric Co. Kenamerica Resources, Inc. Kentucky Power Co. Lafayette Utilities System Louisiana Chemical Association Louisiana Department of Environmental Quality Louisiana Public Service Commission Luminant Big Brown Mining Company, LLC Luminant Energy Company, LLC Luminant Generation Company, LLC Luminant Holding Company, LLC Luminant Mining Company, LLC Midwest Food Processors Association Midwest Ozone Group Mississippi Power Co. Mississippi Public Service Commission Municipal Electric Authority of Georgia Murray Energy Corp. National Mining Association National Rural Electric Cooperative Association Northern States Power Co. Oak Grove Management Company, LLC Ohio Power Co. Ohio Valley Coal Co. OhioAmerica Energy, Inc. Peabody Energy Corp. Public Service Company of Oklahoma Public Utility Commission of Texas Railroad Commission of Texas ii USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Sandow Power Company, LLC South Mississippi Electric Power Association Southern Company Services, Inc. Southern Power Co. Southwestern Electric Power Co. Southwestern Public Service Co. State of Alabama State of Florida State of Georgia State of Indiana State of Kansas State of Louisiana State of Michigan State of Nebraska State of Ohio State of Oklahoma State of South Carolina State of Texas State of Wisconsin Sunbury Generation LP Sunflower Electric Power Corp. Texas Commission on Environmental Quality Texas General Land Office United Mine Workers of America UtahAmerica Energy, Inc. Utility Air Regulatory Group Westar Energy, Inc. Western Farmers Electric Cooperative Wisconsin Cast Metals Association Wisconsin Manufacturers and Commerce Wisconsin Paper Council, Inc. Wisconsin Public Service Corp. Intervenors for Petitioners San Miguel Electric Cooperative City of New York (Nos. 11-1388 and 11-1395 only) State of New York (Nos. 11-1388 and 11-1395 only) iii Page 4 of 52 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 5 of 52 Amici for Petitioners Putnam County, Georgia Industrial Energy Consumers of America Southeastern Legal Foundation, Inc. Respondents United States Environmental Protection Agency (“EPA”) EPA Administrator Gina McCarthy (substituted for former EPA Administrator Lisa Perez Jackson) Intervenors for Respondents American Lung Association Calpine Corp. City of Bridgeport, Connecticut City of Chicago City of New York (all but Nos. 11-1388 and 11-1395) City of Philadelphia Clean Air Council District of Columbia Environmental Defense Fund Exelon Corp. Mayor and City Council of Baltimore Natural Resources Defense Council Public Service Enterprise Group, Inc. Sierra Club State of Connecticut State of Delaware State of Illinois State of Maryland State of Massachusetts State of New York (all but Nos. 11-1388 and 11-1395) State of North Carolina State of Rhode Island State of Vermont iv USCA Case #11-1302 (B) Document #1526530 Filed: 12/10/2014 Page 6 of 52 Rulings Under Review All petitions for review challenge EPA’s final rule entitled “Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals,” 76 FR 48,208 (Aug. 8, 2011) (“the Transport Rule”), which appears at pages 277 to 552 of the joint appendix (“JA”). (C) Related Cases All of the petitions for review consolidated under Case No. 11-1302 are related. They have previously been reviewed by both this Court and the Supreme Court. See EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 (2014); EME Homer City Generation, L.P. v. EPA, 696 F.3d 7 (D.C. Cir. 2012). The Rule 28(a)(1) statement in the Industry and Labor Petitioners’ opening brief on remand identifies and describes all other related cases. v USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 7 of 52 TABLE OF CONTENTS Certificate as to Parties, Rulings, and Related Cases ............................................... i Table of Authorities .............................................................................................viii Glossary ................................................................................................................xii Jurisdiction ............................................................................................................. 1 Issues ...................................................................................................................... 1 Statutes and Regulations ......................................................................................... 1 Statement ............................................................................................................... 1 Summary ............................................................................................................... 2 Standing................................................................................................................. 4 Standard of Review .................................................................................................5 Argument................................................................................................................5 I. EPA Lacked Statutory Authority To Impose FIPs For The 1997 NAAQS On A Majority Of The Transport Rule States. ...................... 5 A. EPA’s Approval Of CAIR SIPs Deprived The Agency Of FIP Authority For 22 Of The 27 Transport Rule States. ...........5 B. EPA’s Efforts To Revive Its 1997 NAAQS FIP Authority With Respect To These 22 States Were Unlawful. .................. 8 1. Section 7410(k)(6) cannot authorize retroactive— and immediate—nullification of EPA’s CAIR SIP approvals. ...................................................................... 9 2. EPA’s “correct[] the deficiency” argument fails. ......... 14 3. This error requires vacatur of the entire rule. ................ 15 vi USCA Case #11-1302 II. III. Document #1526530 Filed: 12/10/2014 Page 8 of 52 EPA’s Implementation Of The Good-Neighbor Provision’s “Interfere With Maintenance” Prong Is Unlawful............................ 16 A. EPA Was Required To Give The Statute’s “Maintenance” Prong Independent Effect. ............................ 16 B. EPA’s Implementation Of The “Maintenance” Prong Is Contrary To The Text Of The Statute And This Court’s Precedent. .............................................................................. 20 At The Very Least, The Transport Rule Is Invalid As Applied To Several Petitioners.......................................................................24 A. The Transport Rule Violates This Court’s And The Supreme Court’s Express Prohibitions. ................................. 24 1. The Transport Rule is invalid as applied to Texas........ 24 2. The Transport Rule is invalid as applied to States linked to areas not designated “nonattainment.” ..........26 B. EPA Violated Notice-And-Comment Requirements. ............. 28 C. EPA Lacked Authority To Promulgate Certain FIPs With Respect To The 2006 NAAQS. .............................................. 31 Conclusion ............................................................................................................ 33 Certificate of Compliance ..................................................................................... 39 Certificate of Service............................................................................................. 39 vii USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 9 of 52 TABLE OF AUTHORITIES Cases Bowen v. Georgetown Univ. Hosp., 488 U.S. 204 (1988) .......................................... 11 Davis Cnty. Solid Waste Mgmt. v. EPA, 101 F.3d 1395 (D.C. Cir. 1996).................. 13 *EME Homer City Generation, L.P. v. EPA, 696 F.3d 7 (D.C. Cir. 2012) ........................................................ v, 1, 2, 10, 19, 21, 23, 24 Envtl. Integrity Project v. EPA, 425 F.3d 992 (D.C. Cir. 2005) .......................... 28, 31 *EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 (2014) .............................................................. v, 2, 5, 15, 24, 25, 26, 32 Fertilizer Inst. v. EPA, 935 F.2d 1303 (D.C. Cir. 1991) ...........................................30 Massachusetts v. EPA, 549 U.S. 497 (2007) ..............................................................5 North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008), modified on reh’g, 550 F.3d 1176 (D.C. Cir. 2008) ................................. 7, 15, 18, 19, 20 Sierra Club v. EPA, 292 F.3d 895 (D.C. Cir. 2002) ................................................ 4 Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506 (D.C. Cir. 1983) .............................................................................................. 28, 30 Texas v. EPA, 726 F.3d 180 (D.C. Cir. 2013) ................................................ 9, 10, 11 Train v. NRDC, 421 U.S. 60 (1975)................................................................. 31, 32 Union Oil Co. v. EPA, 821 F.2d 678 (D.C. Cir. 1987) ............................................ 28 Virginia v. EPA, 108 F.3d 1397 (D.C. Cir. 1997) .................................................... 33 * Authorities upon which we chiefly rely are marked with asterisks. viii USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 10 of 52 Statutes and Rules 5 U.S.C. 551(4) ..................................................................................................... 12 5 U.S.C. 553(b) ..................................................................................................... 14 5 U.S.C. 553(b)(B) ................................................................................................ 13 42 U.S.C. 1857c-5(c)(1) (1970) .............................................................................. 32 42 U.S.C. 7407(d) .................................................................................................26 42 U.S.C. 7407(d)(3)(E) ....................................................................................... 17 42 U.S.C. 7407(d)(3)(E)(iv).............................................................................17, 21 42 U.S.C. 7410(a)(1) ............................................................................................. 16 42 U.S.C. 7410(a)(2)(A) ................................................................................. 16, 26 *42 U.S.C. 7410(a)(2)(D)(i)(I) .................................................................... 1, 18, 19 42 U.S.C. 7410(a)(2)(H)(ii) .................................................................................. 18 42 U.S.C. 7410(a)(2)(I)................................................................................... 17, 26 42 U.S.C. 7410(c) ........................................................................................... 32, 33 *42 U.S.C. 7410(c)(1) ..................................................... 2, 5, 6, 11, 12, 14, 15, 16, 32 42 U.S.C. 7410(c)(1)(A)................................................................................ 5, 9, 14 42 U.S.C. 7410(c)(1)(B) .................................................................................... 5, 14 42 U.S.C. 7410(k)(3) ......................................................................................6, 7, 13 42 U.S.C. 7410(k)(5) ......................................................................... 2, 11, 12, 13, 15 42 U.S.C. 7410(k)(6)........................................................ 2, 3, 8, 9, 10, 11, 12, 13, 14 42 U.S.C. 7502(c) ................................................................................................. 17 ix USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 11 of 52 42 U.S.C. 7502(c)(1) ............................................................................................. 21 42 U.S.C. 7502(c)(6)............................................................................................. 21 42 U.S.C. 7505a ...............................................................................................17, 21 42 U.S.C. 7505a(a) ................................................................................................ 17 42 U.S.C. 7505a(d) ..........................................................................................17, 18 42 U.S.C. 7601(a) ................................................................................................... 1 42 U.S.C. 7607(b)(1) ............................................................................................... 1 42 U.S.C. 7607(d)(3) ........................................................................................... 28 42 U.S.C. 7607(d)(9) ..............................................................................................5 D.C. CIR. R. 28(a)(1) ...............................................................................................v D.C. Cir. R. 28(a)(5) ............................................................................................... 1 Federal Regulatory Material 70 FR 21,147 (Apr. 25, 2005) ................................................................................. 6 70 FR 25,162 (May 12, 2005) ............................................................................ xii, 6 71 FR 25,328 (Apr. 28, 2006) ............................................................................ 6, 23 72 FR 55,659 (Oct. 1, 2007)............................................................................... 6, 13 74 FR 38,536 (Aug. 4, 2009) ...................................................................................7 74 FR 62,496 (Nov. 30, 2009) .................................................................................7 75 FR 42,018 (July 20, 2010) ..................................................................... 22, 23, 29 75 FR 45,210 (Aug. 2, 2010) ........................................................................... 29, 30 x USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 12 of 52 75 FR 58,312 (Sept. 24, 2010) .............................................................................. 22 76 FR 29,652 (May 23, 2011) ................................................................................29 76 FR 43,143 (July 20, 2011).................................................................................. 31 76 FR 48,208 (Aug. 8, 2011) ........................... v, xii, 2, 4, 5, 7, 8, 9, 11, 12, 13, 14, 15, 16, 20, 23, 24, 26, 27, 28, 29, 30, 31 76 FR 74,000 (Nov. 30, 2011) ............................................................................... 27 78 FR 4,341 (Jan. 22, 2013) ................................................................................... 27 78 FR 5,306 (Jan. 25, 2013) ................................................................................... 27 78 FR 53,272 (Aug. 29, 2013) ................................................................................ 27 78 FR 57,270 (Sept. 18, 2013)................................................................................ 27 79 FR 15,019 (Mar. 18, 2014) ................................................................................ 27 79 FR 22,415 (Apr. 22, 2014) .......................................................................... 27, 28 Other Authorities Br. for Fed. Pet’rs, EME Homer, 134 S. Ct. 1584 (2014) (No. 12-1182) ................. 15 EPA, Green Book, PM-2.5 (2006 Standard) Area Information, http://www.epa.gov/airquality/greenbook/rindex.html ....................... 26–27 Order, EME Homer, No. 11-1302 (Oct. 23, 2014) ............................................ 28, 39 Henry A. Waxman, et al., Roadmap to Title I of the Clean Air Act Amendments of 1990: Bringing Blue Skies Back to America’s Cities, 21 ENVTL. L. 1843 (1991) .................................................................. 10 xi USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 13 of 52 GLOSSARY EPA United States Environmental Protection Agency CAA Clean Air Act CAIR Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NOx SIP Call, 70 FR 25,162 (May 12, 2005) FIP Federal Implementation Plan JA Joint Appendix NAAQS National Ambient Air Quality Standard(s) SIP State Implementation Plan Transport Rule Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals 76 FR 48,208 (Aug. 8, 2011) xii USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 14 of 52 JURISDICTION EPA promulgated the Transport Rule on August 8, 2011 under 42 U.S.C. 7601(a). Petitions for review were timely filed on or before October 7, 2011, invoking the Court’s jurisdiction under 42 U.S.C. 7607(b)(1). ISSUES 1. Whether EPA lacked statutory authority to impose federal implementation plans (“FIPs”) with respect to the 1997 national ambient air quality standards (“NAAQS”) on States whose state implementation plans (“SIPs”) addressing those standards had been fully approved by EPA. 2. Whether EPA’s implementation of the good-neighbor provision’s “interfere with maintenance” prong, 42 U.S.C. 7410(a)(2)(D)(i)(I), was unlawful. 3. Whether the Transport Rule is invalid as applied to several States. STATUTES AND REGULATIONS The petitioners’ joint addendum pursuant to D.C. Circuit Rule 28(a)(5) reproduces the statutes and regulatory material cited in this brief. STATEMENT The facts and procedural history of these consolidated challenges to EPA’s Transport Rule are set forth in EME Homer City Generation, L.P. v. EPA, 696 F.3d 7, 11–19 (D.C. Cir. 2012). Although the Supreme Court reversed this Court’s judgment vacating the rule, it agreed with significant portions of this Court’s USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 15 of 52 analysis and identified challenges to be resolved on remand. EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 1599 n.12, 1608–09 (2014). The first of these challenges concerns EPA’s imposition of FIPs with respect to the two 1997 standards on several upwind States even though EPA had fully approved those States’ good-neighbor SIP revisions for the 1997 standards. See id. at 1599 n.12; 76 FR 48,208, 48,219–22 (Aug. 8, 2011); see also EME Homer, 696 F.3d at 31 n.29 (noting this challenge). The second concerns EPA’s implementation of the good-neighbor provision’s “interfere with maintenance” prong. See EME Homer, 134 S. Ct. at 1604 n.18; 76 FR at 48,233–36, 48,246–64; see also EME Homer, 696 F.3d at 27 n.25 (noting the limits of EPA’s authority under this prong). The third concerns whether the Transport Rule is invalid as applied to several States. See EME Homer, 134 S. Ct. at 1608–09; infra Part III (citing the portions of the record that support the as-applied challenges presented in this brief). SUMMARY 1. EPA’s approval of 22 States’ Clean Air Interstate Rule (“CAIR”) SIP revisions extinguished the agency’s authority under 42 U.S.C. 7410(c)(1) to impose Transport Rule FIPs on those States. EPA should have issued a SIP call under section 7410(k)(5), and its invocation of section 7410(k)(6) was unlawful for two 2 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 16 of 52 reasons. First, section 7410(k)(6) authorizes EPA to correct errors that were errors at the time they were made, not to retroactively rescind, based on later developments, earlier statements that had unavoidable legal consequences. Second, EPA made its “corrections” without using notice-and-comment rulemaking, but section 7410(k)(6) requires EPA to make any corrections “in the same manner as the approval.” EPA’s assertion that the SIPs it approved did not correct the deficiency that should have required disapproval is untenable, and because EPA’s errors infect a large number of the Transport Rule’s nonseverable FIPs, the proper relief is vacatur of the entire rule. 2. In concluding that CAIR was invalid, this Court explained that EPA was required to give independent effect to the good-neighbor provision’s “contribute significantly to nonattainment” and “interfere with maintenance” prongs. EPA, however, failed to do so in the Transport Rule. It instead adopted a single methodology for regulating emissions under both prongs, failing to consider whether the Transport Rule’s “maintenance” requirements were necessary to prevent upwind emissions from reaching specific downwind maintenance areas and threatening continued NAAQS attainment in those areas. That approach led EPA to require Transport Rule “maintenance” reductions that exceed what the Clean Air Act (“CAA”) and circuit precedent permit. 3 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 17 of 52 3. The Supreme Court agreed with this Court that EPA may not regulate upwind States under the good-neighbor provision in a manner that is unnecessary to achieve NAAQS attainment in every downwind State to which an upwind State is linked. EPA violated this prohibition with respect to Texas and several other States that were linked to areas already attaining the standards addressed in the Transport Rule. EPA’s promulgation of the Transport Rule also violated notice-andcomment requirements. This challenge, which was raised but not resolved in the initial phase of proceedings before this Court, likewise requires vacatur. Finally, Kansas and Indiana argue that certain Transport Rule FIPs addressing the 2006 fine-particulate standard are unlawful because EPA’s Administrator signed the Transport Rule before the relevant SIP disapprovals were published in the Federal Register. STANDING The Courts’ opinions in these cases demonstrate the petitioners’ standing. Petitioners are the objects of the action at issue, see Sierra Club v. EPA, 292 F.3d 895, 899–900 (D.C. Cir. 2002), and the Transport Rule injures States by overriding their statutory right to control emissions through SIPs. See, e.g., 76 FR at 48,219– 4 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 18 of 52 22. Vacating the rule would provide redress and prompt EPA to reconsider its action. See Massachusetts v. EPA, 549 U.S. 497, 518 (2007). STANDARD OF REVIEW The Court should vacate the Transport Rule upon concluding that it is arbitrary or capricious, is in excess of EPA’s statutory authority, or was promulgated without observance of required procedures. 42 U.S.C. 7607(d)(9). ARGUMENT I. EPA LACKED STATUTORY AUTHORITY TO IMPOSE FIPS FOR THE 1997 NAAQS ON A MAJORITY OF THE TRANSPORT RULE STATES. A. EPA’s Approval Of CAIR SIPs Deprived The Agency Of FIP Authority For 22 Of The 27 Transport Rule States. 1. 42 U.S.C. 7410(c)(1) is the exclusive source of EPA’s FIP authority. EPA must promulgate a FIP whenever “a State has failed to make a required [SIP] submission” or EPA “disapproves a [SIP] submission in whole or in part.” 42 U.S.C. 7410(c)(1)(A), (B). Section 7410(c)(1)’s final sentence, however, deprives EPA of FIP authority if “the State corrects the deficiency, and [EPA] approves the [SIP] or [SIP] revision, before [EPA] promulgates such [FIP].” “[T]he deficiency” is what allows EPA to make a finding of failure to submit a SIP under section 7410(c)(1)(A) or to disapprove a SIP submission under section 7410(c)(1)(B). See EME Homer, 134 S. Ct. at 1594 (explaining that EPA’s FIP authority derives from a 5 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 19 of 52 determination “that a State has failed to submit an adequate SIP”). A State “corrects th[at] deficiency” by submitting an adequate SIP. 42 U.S.C. 7410(c)(1). Under 42 U.S.C. 7410(k)(3), EPA has a nondiscretionary duty to approve a State’s “[SIP] submittal as a whole if it meets all of the applicable requirements of [the CAA].” And as EPA has explained, “[o]nce a SIP is fully approved, EPA no longer has authority for the FIP[]” that previously governed the State’s obligations, and the FIP must therefore be withdrawn. 72 FR 55,659, 55,660 (Oct. 1, 2007) (describing a scenario in which EPA approves SIPs to replace FIPs). 2. In April 2005, EPA issued a blanket finding that “States ha[d] failed” to submit SIPs to satisfy their good-neighbor obligations with respect to the 1997 ozone and fine-particulate NAAQS. 70 FR 21,147, 21,148 (Apr. 25, 2005); see JA3167–78. The next month, EPA promulgated CAIR, which defined the 1997NAAQS good-neighbor SIP requirements for 28 States, giving those States a year and a half to submit SIPs addressing their obligations under CAIR and thus prevent application of CAIR FIPs. 70 FR 25,162, 25,162, 25,167 (May 12, 2005); 71 FR 25,328, 25,328, 25,330, 25,340 (Apr. 28, 2006). Consistent with 42 U.S.C. 7410(c)(1) and (k)(3), EPA explained that approval of CAIR SIPs would extinguish its FIP authority for the 1997 NAAQS and lead to withdrawal of any CAIR FIPs that had already issued. 71 FR at 25,333. 6 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 20 of 52 3. In North Carolina v. EPA, this Court sustained a number of challenges to CAIR but remanded the rule without vacatur. 531 F.3d 896, 930 (D.C. Cir. 2008), modified on reh’g, 550 F.3d 1176, 1178 (D.C. Cir. 2008). Accordingly, both before and after North Carolina, CAIR was effective and binding on EPA and the States. See 74 FR 62,496, 62,496 (Nov. 30, 2009). When presented with CAIR-compliant SIP revisions, EPA thus had a nondiscretionary duty to approve them “as a whole.” 42 U.S.C. 7410(k)(3); see 74 FR 38,536, 38,537 (Aug. 4, 2009) (confirming that “EPA’s role is to approve State choices, provided that they meet the criteria of the [CAA]”). If EPA had concluded that any of those submissions failed to satisfy any portion of a State’s 1997 NAAQS good-neighbor obligations as defined in CAIR, EPA’s duty would have been to approve the submissions “in part and disapprove [them] in part,” 42 U.S.C. 7410(k)(3), preserving EPA’s FIP authority (and obligation) to cure the remaining deficiencies. All told, EPA approved fifteen CAIR SIP revisions before North Carolina and seven thereafter. See 76 FR at 48,220–21 (citing approvals for Alabama, Arkansas, Connecticut, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Virginia, and West Virginia). None 7 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 21 of 52 of those submissions was disapproved, and none was approved in part and disapproved in part; rather, each of the 22 CAIR SIPs was approved in full. See id. In approving these 22 CAIR SIPs, EPA terminated, for each State, its FIP authority arising from the 2005 finding of failure. See supra Parts I.A.1–2. B. EPA’s Efforts To Revive Its 1997 NAAQS FIP Authority With Respect To These 22 States Were Unlawful. When EPA promulgated the Transport Rule, it recognized the threat to its 1997-NAAQS FIP authority that approval of the 22 States’ CAIR SIPs presented. 76 FR at 48,219 (acknowledging comments on this point). But because EPA wanted to maintain a single, accelerated timeline for all of the Transport Rule States, it attempted to “unring the bell” with respect to its CAIR SIP approvals and reclaim FIP authority arising from the 2005 finding of failure to submit SIPs—authority that EPA’s CAIR SIP approvals had extinguished. See id.; see also 76 FR at 48,213 (Table III–1), 48,219 n.12 (reflecting imposition of 1997-NAAQS FIPs on 19 of the 22 States whose CAIR SIPs had been fully approved). EPA deployed two maneuvers in its effort to accomplish that feat. First, it attempted to invoke 42 U.S.C. 7410(k)(6), see id. at 48,217, to alter the past to service its present need by “rescind[ing] any statements [in its CAIR SIP approvals] suggesting that the [CAIR] SIP submissions satisfied or relieved states of the obligation to submit SIPs to satisfy the requirements of [the good-neighbor 8 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 22 of 52 provision] or that EPA was relieved of its obligation and authority to promulgate FIPs under [that provision].” Id. at 48,219. Second, EPA contended that the CAIR SIPs it had initially approved failed to “correct[] the deficiency,” 42 U.S.C. 7410(c)(1)(A), that had prompted it to issue the 2005 finding of failure. 76 FR at 48,219. As explained below, neither maneuver was lawful. And because the Transport Rule’s FIPs are nonseverable, the Court should vacate the entire rule. 1. Section 7410(k)(6) cannot authorize retroactive—and immediate—nullification of EPA’s CAIR SIP approvals. a. This is not the first time in recent years that EPA has attempted to stretch the boundaries of its section-7410(k)(6) “[c]orrections” power. In connection with its regulation of greenhouse gases, EPA attempted to wield that power to retroactively change an earlier SIP “full approval” into a “partial approval, partial disapproval.” Texas v. EPA, 726 F.3d 180, 204 (D.C. Cir. 2013) (Kavanaugh, J., dissenting). Although the Texas majority did not address the merits of that effort, see id. at 199 (concluding that the petitioners lacked standing), the dissent observed that EPA’s invocation of section 7410(k)(6) was improper because, at the time of the full approval, the applicable authorities did not require partial disapproval. See id. at 204 (Kavanaugh, J., dissenting). 9 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 23 of 52 In Texas, EPA thus attempted to use section 7410(k)(6) to retroactively create SIP requirements where none existed before. See id. Here, EPA attempted to use section 7410(k)(6) to retroactively alter SIP requirements that did exist, had been satisfied, and led to EPA’s full approval of 22 SIPs. See supra Part I.A. Both invocations of section 7410(k)(6) were unlawful. Because the petitioners here have standing, the Court should hold that EPA lacked statutory authority to impose FIPs on the States subjected to EPA’s section-7410(k)(6) treatment in the Transport Rule and, in so doing, prevent further abuse of this provision. b. Entitled “Corrections,” section 7410(k)(6) was intended merely to “enable EPA to deal promptly with clerical errors or technical errors. It [wa]s not intended to offer a route for EPA to reevaluate its policy judgements,” Henry A. Waxman, et al., Roadmap to Title I of the Clean Air Act Amendments of 1990: Bringing Blue Skies Back to America’s Cities, 21 ENVTL. L. 1843, 1924–25 (1991), or to give EPA the extraordinary power to undo the legal consequences of its past actions. As the Court has already suggested, the Transport Rule’s invocation of section 7410(k)(6) was unlawful for two independent reasons. See EME Homer City, 696 F.3d at 31 n.29. i. Section 7410(k)(6) authorizes corrections only when a past EPA action “was in error,” meaning that the action was erroneous under the law in existence 10 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 24 of 52 at the time. See Texas, 726 F.3d at 204 (Kavanaugh, J., dissenting). The provision cannot be used to rescind key statements in a SIP approval based on subsequent developments in judicial doctrine or agency rulemaking. That is the office of the preceding section, which requires EPA to issue a “SIP call” whenever it finds that a SIP is “substantially inadequate to attain or maintain the relevant [NAAQS] … or to otherwise comply with any requirement of [the CAA].” 42 U.S.C. 7410(k)(5). Yet EPA relied on section 7410(k)(6), not section 7410(k)(5), reasoning that North Carolina’s invalidation of CAIR “meant that the CAIR SIPs were not adequate to satisfy [the good neighbor provision’s] mandate.” 76 FR at 48,217, 48,219. It bears emphasis, however, that EPA did not stop approving CAIR SIPs when North Carolina was decided. As already noted, seven of the subsequently “corrected” approvals post-date North Carolina. See id. at 48,221. In any event, EPA’s reasoning is flawed. To begin, condoning EPA’s use of section 7410(k)(6) would impermissibly allow the Transport Rule to apply retroactively, “altering the past legal consequences of past actions.” Bowen v. Georgetown Univ. Hosp., 488 U.S. 204, 219 (1988) (Scalia, J., concurring) (emphasis omitted). The Transport Rule altered the past consequences of EPA’s CAIR SIP approvals, purporting to make them prolong, rather than terminate, EPA’s authority to issue FIPs. See 42 U.S.C. 11 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 25 of 52 7410(c)(1) (requiring a FIP to issue “within 2 years after” a finding of failure to submit a SIP or a SIP disapproval); 76 FR at 48,219 (referencing the 2005 finding of failure on which EPA premised its 2011 Transport Rule FIP authority for the States subjected to EPA’s section-7410(k)(6) treatment, see JA3167–78). That contradicts Bowen, which forbids retroactive rulemaking absent clear and unambiguous statutory authorization, 488 U.S. at 208, and the Administrative Procedure Act, which defines “rule” as “an agency statement of . . . future effect.” 5 U.S.C. 551(4). Furthermore, it exceeds the admitted limits of EPA’s authority under section 7410(c)(1). See 76 FR at 48,219 & n.15, 48,220 (conceding that EPA lacks statutory authority to restart the “within 2 years” “FIP clock”). EPA’s construction of “error” in section 7410(k)(6) also cannot be reconciled with section 7410(k)(5)’s SIP-call provision. Under section 7410(k)(5), EPA “shall” issue a SIP call whenever it finds a SIP “substantially inadequate” to maintain a NAAQS or comply with any CAA requirement. The provision requires EPA to “notify the State of the inadequacies” and provide an opportunity for the State to submit a revised SIP. 42 U.S.C. 7410(k)(5). A FIP cannot issue until after EPA finds that the State failed to submit the necessary SIP revisions. 42 U.S.C. 7410(c)(1). 12 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 26 of 52 EPA’s understanding of the word “error” extends section 7410(k)(6)’s correction power to every circumstance described in section 7410(k)(5). Whenever an EPA-approved SIP is found inadequate to comply with EPA’s current understanding of the CAA, EPA can simply declare its earlier approval an “error” and immediately impose a FIP without complying with section 7410(k)(5). That interpretation renders section 7410(k)(5)’s language meaningless and is therefore invalid. See Davis Cnty. Solid Waste Mgmt. v. EPA, 101 F.3d 1395, 1404 (D.C. Cir. 1996). In short, EPA’s SIP approvals were not in error when made. They were mandated under section 7410(k)(3), which directs EPA to “approve [a SIP] … if it meets all of the applicable requirements of [the CAA].” Accordingly, EPA could not use section 7410(k)(6) to “correct” its CAIR SIP approvals. ii. EPA’s use of section 7410(k)(6) is unlawful for another, independent reason. Any revisions of past agency action must be made “in the same manner as” the putative erroneous action. 42 U.S.C. 7410(k)(6). Although EPA issued its SIP approvals through notice-and-comment rulemaking, see, e.g., 72 FR at 55,659, its “corrections” did not go through that process. 76 FR at 48,221. EPA’s attempt to invoke the “good cause” exception of 5 U.S.C. 553(b)(B), 76 FR at 48,221–22, fails. Two independent sources of law obligated EPA to use 13 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 27 of 52 notice and comment: 5 U.S.C. 553(b), which is subject to a “good cause” exception, and 42 U.S.C. 7410(k)(6), which is not. Agencies do not have a goodcause license to violate their organic statutes. 2. EPA’s “correct[] the deficiency” argument fails. As already noted, section 7410(c)(1)’s final sentence revokes EPA’s FIP authority when “the State corrects the deficiency” and EPA “approves the [SIP] or [SIP] revision.” In the Transport Rule, EPA admitted it had approved the 22 States’ CAIR SIPs but nevertheless claimed that, in light of North Carolina, those SIPs failed to “correct[] the deficiency,” 42 U.S.C. 7410(c)(1), and therefore did not terminate EPA’s FIP authority. 76 FR at 48,219. That position is untenable. Again, “the deficiency” in section 7410(c)(1) is the deficiency that caused EPA to (A) find that a State failed to submit a SIP or (B) disapprove a SIP that was submitted. See supra Part I.A.1. It cannot mean a deficiency that arises only upon later developments. A State “corrects the deficiency” by submitting a new SIP that responds to the concerns that prompted EPA to act under section 7410(c)(1)(A) or (B) and that complies with every reasonably knowable legal obligation at the time of EPA’s disapproval or finding of failure. Each of the 22 States’ SIPs that EPA approved did so. See supra Part I.A.2–3. 14 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 28 of 52 EPA’s construction of section 7410(c)(1) rewrites the statute to require a State to correct all deficiencies that are currently known and that may become known. That interpretation departs from the natural reading of the text and would render the final sentence of section 7410(c)(1) useless in constraining EPA’s power, allowing the agency to circumvent section 7410(k)(5)’s procedural protections merely by declaring a previously approved SIP deficient. No principle of deference allows an agency to interpret its organic statute in such an atexutal and self-aggrandizing manner. 3. This error requires vacatur of the entire rule. As EPA explained in the Supreme Court, each State’s good-neighbor obligations are intertwined with other States’ good-neighbor obligations under the 1997 and 2006 NAAQS. See Br. for Fed. Pet’rs 45–53, EME Homer, 134 S. Ct. 1584 (2014) (No. 12-1182); see also EME Homer, 134 S. Ct. at 1604 (noting that “the nonattainment of downwind States results from the collective and interwoven contributions of multiple upwind States”); 76 FR at 48,252–53 (Table VI.B–3 & n.a) (reflecting EPA’s conclusion that Transport Rule FIPs requiring more stringent emissions reductions in some States than others will cause emissions shifting, resulting in greater emissions in States whose Transport Rule FIPs are more lenient); cf. North Carolina, 531 F.3d at 929 (noting that CAIR’s components 15 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 29 of 52 “must stand or fall together”). The Transport Rule FIPs, in other words, are nonseverable. And as already noted, EPA’s violation of section 7410(c)(1) affects a substantial portion of the rule. Thirty-one of its fifty-nine FIPs implement goodneighbor obligations under the 1997 NAAQS for States whose CAIR SIPs EPA had previously approved, 76 FR at 48,213 (Table III–1), 48,219 n.12, 48,220–21, and the Transport Rule’s regional trading programs for the 1997 standards could not function with a majority of the covered States excluded. Accordingly, the entire rule should be vacated. II. EPA’S IMPLEMENTATION OF THE GOOD-NEIGHBOR PROVISION’S “INTERFERE WITH MAINTENANCE” PRONG IS UNLAWFUL. A. EPA Was Required To Give The Statute’s “Maintenance” Prong Independent Effect. 1. Once EPA promulgates a NAAQS, States must develop “attainment” SIPs that provide for “implementation, maintenance, and enforcement” of the NAAQS. 42 U.S.C. 7410(a)(1). In formulating an attainment plan, a State must impose on its sources “emission limitations and other control measures, means, or techniques … as may be necessary or appropriate to meet the applicable requirements of [the CAA].” 42 U.S.C. 7410(a)(2)(A). Because the NAAQSpollutant concentrations in each location in a State will reflect contributions from 16 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 30 of 52 both in-state emissions and upwind-state emissions, and because States must demonstrate attainment and maintenance of the NAAQS based on existing NAAQS-pollutant concentrations, any State’s demonstration will necessarily account for present emissions from existing sources—both within and outside of the State. When a State is unable to achieve attainment, its SIP must satisfy additional requirements for areas designated “nonattainment.” 42 U.S.C. 7410(a)(2)(I), 7502(c). If air quality sufficiently improves, the area may be redesignated from nonattainment to attainment, see 42 U.S.C. 7407(d)(3)(E), provided the State submits a “[m]aintenance plan[]” that assures “maintenance of the [NAAQS] … for at least 10 years after the redesignation.” 42 U.S.C. 7505a(a); see 42 U.S.C. 7407(d)(3)(E)(iv). Maintenance plans must contain “contingency provisions” to ensure that the State will “promptly correct any violation of the [NAAQS].” 42 U.S.C. 7505a(d). Because both attainment plans and maintenance plans contain emissions limitations necessary to maintain NAAQS compliance, and because those NAAQS-compliant levels include emissions contributions from upwind States, only emissions that were not considered in the SIP attainment/maintenance demonstration (or in developing any contingency provisions), such as increased 17 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 31 of 52 upwind-state emissions, could trigger a requirement for SIP revision. 42 U.S.C. 7410(a)(2)(H)(ii), 7505a(d). 2. The distinction between regulating emissions causing nonattainment and regulating increased emissions that could threaten continued attainment is reflected in the text of the good-neighbor provision, which contains two distinct prongs for addressing emissions from one State that affect air quality in another. The first prong focuses on downwind nonattainment areas, prohibiting all upwindstate emissions that “contribute significantly to nonattainment in … any other State.” 42 U.S.C. 7410(a)(2)(D)(i)(I). The second prong focuses on downwind attainment areas and addresses only those upwind-state emissions that will “interfere with maintenance [of NAAQS attainment] by … any other State.” Id. Because SIPs must assure maintenance of NAAQS-compliant concentrations that include contributions from upwind States, the potential candidates for regulation under the good-neighbor provision’s “maintenance” prong are upwind-state emissions greater than those assumed in the upwind-state SIP’s attainment/maintenance demonstration. 3. These fundamental differences led the Court to hold in North Carolina that the two prongs of the good-neighbor provision must be given separate, 18 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 32 of 52 independent meanings. 531 F.3d at 909–10. And as the Court explained earlier in this litigation, [t]o require a State to reduce “amounts” of emissions pursuant to the “interfere with maintenance” prong, EPA must show … that those “amounts” from an upwind State … will reach a specific maintenance area in a downwind State and push that maintenance area back over the NAAQS in the near future. Put simply, the “interfere with maintenance” prong of the statute is not an open-ended invitation for EPA to impose reductions on upwind States. Rather, it is a carefully calibrated and commonsense supplement to the “contribute significantly” requirement. EME Homer, 696 F.3d at 27 n.25. To give the “maintenance” prong independent effect, EPA must therefore focus not on upwind-state emissions that were already accounted for in developing attainment SIPs, but instead on any additional upwindstate emissions that would increase downwind concentrations not considered in the attainment/maintenance demonstration. Reductions are required only where increased upwind-state emissions “will … interfere” with continued NAAQS attainment “by … any [downwind] State.” 42 U.S.C. 7410(a)(2)(D)(i)(I); see, e.g., JA3210–22 (EPA memo describing maintenance-plan requirements for areas redesignated attainment). 19 USCA Case #11-1302 B. Document #1526530 Filed: 12/10/2014 Page 33 of 52 EPA’s Implementation Of The “Maintenance” Prong Is Contrary To The Text Of The Statute And This Court’s Precedent. Rather than recognizing the distinct focus of the “maintenance” prong, EPA simply adopted the same methodology used to implement the statute’s “contribute significantly” prong, with the exception that EPA used more stringent ambient thresholds to establish “maintenance” linkages. 76 FR at 48,233–36. Like EPA’s significant-contribution methodology, EPA’s maintenance methodology evaluates total emissions from an upwind State (i.e., all mobile, residential, industrial, and utility-sectors emissions). Id. at 48,224–25. When those upwind-state emissions are projected to contribute concentrations that exceed “one percent” of the rule’s ambient threshold, EPA’s “maintenance” methodology mandates “cost-effective” reductions in total utility-sector upwind-state emissions but no reductions in upwind emissions from any other sector. Id. at 48,246–64. This “contribute significantly” approach to “interfere with maintenance” violates North Carolina and runs afoul of the CAA in several respects. 1. To begin, EPA’s approach violates the text of the good-neighbor provision by failing to identify and analyze only those upwind emissions that might actually threaten continued attainment. Upwind-state emissions that contribute to concentrations that are below the NAAQS in a downwind State, and that have already been accounted for in that State’s attainment demonstration, cannot, by 20 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 34 of 52 definition, “interfere with maintenance.” Moreover, EPA’s methodology ignores the fundamental difference between areas that are meeting NAAQS and areas that are not. In nonattainment areas, because the air-quality status quo is unacceptable, all emissions contributing to nonattainment are targeted for reduction. 42 U.S.C. 7502(c)(1), (c)(6). In areas that have attained standards, by contrast, the air-quality status quo is the regulatory end sought by Congress, and only increased emissions that threaten that status quo “interfere with maintenance” of the NAAQS and thus are targets for additional regulation. See 42 U.S.C. 7407(d)(3)(E)(iv), 7505a. Yet EPA’s “maintenance” methodology requires substantial reductions in upwind-state utility emissions without regard to whether concentrations resulting from those emissions were accounted for in the attainment-plan or maintenanceplan demonstration for the downwind attainment area. Nothing in EPA’s methodology is directed at identifying increased upwind-state emissions that threaten to “push … [a downwind-state attainment] area back over the NAAQS in the near future.” EME Homer, 696 F.3d at 27 n.25. And a methodology that focuses exclusively on the utility sector for emissions reductions, when emissions from other sectors (e.g., mobile sources) may dominate contributions to downwind-state attainment areas, is not capable of targeting those emissions reductions that the 21 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 35 of 52 “maintenance” analysis required by the language of the Act would select for regulation. 2. The example of Allegan County, Michigan, illustrates how far EPA departed from the statute. In 2010, EPA redesignated Allegan County from nonattainment to attainment of the 1997 ozone standard. 75 FR 58,312, 58,312–13 (Sept. 24, 2010). In so doing, EPA approved Michigan’s maintenance plan for the area, based on a demonstration that ozone concentrations caused by local and upwind-state emissions would register attainment through 2021 by a wide margin. Id.; see 75 FR 42,018, 42,026–28 (July 20, 2010) (proposed rule). To assure attainment beyond 2021, a contingency plan targeted local volatile-organiccompound emissions for possible future reductions. See 75 FR at 42,028–29. According to the maintenance plan, further nitrogen-oxides reductions would have no impact on attainment of the ozone NAAQS in Allegan County. See id. at 42,027. Without regard to this EPA-approved Allegan County maintenance plan, the Transport Rule’s “interfere with maintenance” methodology imposes substantial upwind reductions in utility-sector nitrogen-oxides emissions, ignoring the volatileorganic-compound reductions called for in the Allegan County contingency plan and making no attempt to evaluate the importance of upwind utility-sector nitrogen-oxides emissions relative to other upwind emissions that were linked to 22 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 36 of 52 Allegan County. See 76 FR at 48,233–36. As a result, the Transport Rule’s methodology mandates significant reductions in upwind utility-sector nitrogenoxides emissions that are not necessary to prevent a violation of the ozone NAAQS in Allegan County. 75 FR at 42,027. More specifically, the Transport Rule targeted nine upwind States (Arkansas, Illinois, Indiana, Iowa, Kansas, Missouri, Oklahoma, Texas, and Wisconsin) for the same nitrogen-oxides emissions reductions that would be required if Allegan County were subject to a nonattainment plan. See 76 FR at 48,246 (Table V.D–9). Yet EPA made no showing that these utility-sector emissions threaten to create downwind-state nonattainment “in the near future” (or, for that matter, at any more distant time). EME Homer, 696 F.3d at 27 n.25. This is not how the CAA works. Indeed, as EPA has recognized, “applying controls on upwind sources in these circumstances not only could be environmentally unnecessary, but could even create a perverse incentive for downwind states to increase local emissions.” 71 FR at 25,337. In short, EPA unlawfully failed to adopt a methodology for the goodneighbor provision’s “maintenance” prong that gives that prong independent meaning and comports with the statute as a whole. That deficiency requires vacatur of the Transport Rule. 23 USCA Case #11-1302 III. Document #1526530 Filed: 12/10/2014 Page 37 of 52 AT THE VERY LEAST, THE TRANSPORT RULE IS INVALID AS APPLIED TO SEVERAL PETITIONERS. A. The Transport Rule Violates This Court’s And The Supreme Court’s Express Prohibitions. After agreeing with this Court that “EPA cannot require a State to reduce its output of pollution by more than is necessary to achieve attainment in every downwind State or at odds with the one-percent threshold the Agency has set,” EME Homer, 134 S. Ct. at 1608; accord EME Homer, 696 F.3d at 20–26, 27–28, the Supreme Court recognized the potential for valid as-applied challenges based on these core principles. 134 S. Ct. at 1609. As explained below, several such challenges are valid. 1. The Transport Rule is invalid as applied to Texas. Texas is an exception to the Supreme Court’s general observation that “individual upwind States often ‘contribute significantly’ to nonattainment in multiple downwind locations.” Id. at 1608. In the Transport Rule, EPA determined that Texas contributed significantly to nonattainment of the 1997 fine-particulate standard at the Madison, Illinois monitor alone. 76 FR at 48,241 (Table V.D–2). Similarly, EPA identified East Baton Rouge, Louisiana, as Texas’s single ozone nonattainment linkage. Id. at 48,246 (Table V.D–8); see also id. at 48,246 (Table V.D–9) (linking Texas to Allegan, Michigan for ozone maintenance, rather than 24 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 38 of 52 nonattainment); supra Part II.B.2 (explaining why Allegan was not a proper maintenance linkage). As explained in Part I.A of the Industry and Labor Petitioners’ opening brief on remand, EPA over-controlled Texas for both fine particulate matter and ozone. And in light of Texas’s single nonattainment linkages for the two 1997 NAAQS, the Supreme Court’s discussion of permissible over-control is inapplicable to Texas. See EME Homer, 134 S. Ct. at 1608–09 & n.22 (reflecting that over-control with respect to one downwind location is permissible only as a byproduct of EPA’s efforts to ameliorate air pollution at one or more downwind linkages with more substantial problems). In short, the Transport Rule FIPs for Texas are based on unlawful linkages and impermissibly over-control Texas emissions. In Texas’s view (unlike that of the Industry and Labor Petitioners), this error requires vacatur, at a minimum, of the Transport Rule FIPs for Texas, without remand for mere expansion of Texas’s Transport Rule emissions budgets.1 1. Louisiana also asserts that it should never have been included in the Transport Rule. EPA’s Integrated Planning Model (“IPM”) data is flawed. “Real world” data shows that Louisiana’s emissions fall below the 1% significance threshold established by EPA with respect to every downwind State to which Louisiana was linked. See Louisiana’s Motion For Stay, or, In the Alternative, For Expedited Review (Doc. No. 1334498) at 6–9. In support of its position, Louisiana 25 USCA Case #11-1302 2. Document #1526530 Filed: 12/10/2014 Page 39 of 52 The Transport Rule is invalid as applied to States linked to areas not designated “nonattainment.” As already noted, EPA must designate areas within a State’s borders that are not meeting a NAAQS as “nonattainment” areas. 42 U.S.C. 7407(d). The remainder of the State must be designated “attainment” or “unclassifiable.” Id. After designations are made, “[t]he Act … shifts the burden to States to propose [SIPs] adequate for compliance with the NAAQS.” EME Homer, 134 S. Ct. at 1594. SIP requirements to protect areas designated “attainment” or “unclassifiable” are distinct from SIP requirements for nonattainment areas, both in terms of in-state emissions and transported emissions. See 42 U.S.C. 7410(a)(2)(A), 7410(a)(2)(I). A contribution to a downwind area designated “attainment” cannot, as matter of law, be a significant contribution to nonattainment. In the Transport Rule, however, EPA imposed significant-contribution reduction obligations for the 2006 fine-particulate NAAQS based on linkages to three areas (the Madison and Cook areas in Illinois and the Marion area in Indiana, see 76 FR at 48,242–43 (Table V.D–5)) that EPA has never designated “nonattainment” for that standard. See EPA, Green Book, PM-2.5 (2006 Standard) Area Information, http://www.epa.gov/airquality/greenbook/rindex. incorporates the arguments advanced in Part II.A of the Industry and Labor Petitioners’ opening brief on remand. 26 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 40 of 52 html (last visited December 10, 2014). Each of these areas has been designated either “attainment” or “unclassifiable” since August 2011, when EPA published the Transport Rule. See id. EPA thus had no authority to mandate “significant contribution” reductions based on linkages to any of these areas. This error infects the 2006-NAAQS FIPs for Alabama, Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Missouri, Ohio, Pennsylvania, Tennessee, West Virginia, and Wisconsin. See 76 FR at 48,242–43 (Table V.D–5). Similarly, EPA took final action approving several area redesignations from nonattainment to attainment of Transport Rule NAAQS while the rule was on judicial review. 79 FR 22,415 (Apr. 22, 2014) (Milwaukee, WI); 79 FR 15,019 (Mar. 18, 2014) (Brooke, WV); 78 FR 57,270 (Sept. 18, 2013) (Cuyahoga, OH); 78 FR 53,272 (Aug. 29, 2013) (St. Clair, MI; Wayne, MI); 78 FR 5,306 (Jan. 25, 2013) (Jefferson, AL (2006 fine-particulate NAAQS)); 78 FR 4,341 (Jan. 22, 2013) (Jefferson, AL (1997 fine-particulate NAAQS)); 76 FR 74,000 (Nov. 30, 2011) (East Baton Rouge, LA). The reductions now scheduled to begin January 1, 2015 based on “nonattainment” linkages to these areas, see 76 FR at 48,241–46 (Tables 27 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 41 of 52 V.D–2, V.D–5, V.D–8); Order 3, EME Homer, No. 11-1302 (Oct. 23, 2014) (Doc. No. 1518738) (granting EPA’s motion to lift the stay), are likewise unlawful.2 B. EPA Violated Notice-And-Comment Requirements. 42 U.S.C. 7607(d)(3)’s notice requirements are “more stringent” than the Administrative Procedure Act’s. Union Oil Co. v. EPA, 821 F.2d 678, 681–82 (D.C. Cir. 1987). A final rule must be a “logical outgrowth” of the proposed rule. Envtl. Integrity Project v. EPA, 425 F.3d 992, 996 (D.C. Cir. 2005); see Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 518–19, 548 (D.C. Cir. 1983). EPA made substantial, undisclosed revisions to the Transport Rule’s substance and methodology. Between proposal and finalization, EPA changed “both steps of its significant contribution analysis,” altering its “modeling platforms and modeling inputs” and “its analysis for identifying” significant contribution and maintenance-interference. 76 FR at 48,213. The final rule was thus “significantly different … than originally proposed,” JA3493, and many of its requirements were dramatically more stringent. Numerous States suffered material emissions-budget cuts between the proposed and final rules because of these 2. EPA disregarded emissions inventories, including upwind-state emissions inventories, established through the redesignation process. See, e.g., 79 FR at 22,415 (approving Wisconsin’s emissions inventories). By definition, these inventories are sufficient to demonstrate attainment; any more-restrictive Transport Rule budgets constitute over-control. 28 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 42 of 52 changes. Ohio’s sulfur-dioxide budgets, for example, were slashed by 33% for 2012 and 23% for 2014 and beyond. Compare 75 FR 45,210, 45,291 (Table IV.E–1) (Aug. 2, 2010), with 76 FR at 48,269 (Table VI.F–1). EPA’s notice violation was pronounced with respect to Texas. EPA proposed to exclude Texas from the Transport Rule’s sulfur-dioxide and annual nitrogen-oxides programs based on modeling reflecting that Texas emissions do not significantly contribute to nonattainment of the fine-particulate standard. 75 FR at 45,255–67, 45,282–84. Yet in the final rule, EPA included Texas as a “significant contributor” of fine particulate matter based on data from a single downwind monitor. 76 FR at 48,241 (Table V.D–2). It also established sulfur-dioxide and annual nitrogen-oxides emissions budgets for Texas, imposing reductions that were not subject to notice and comment. Id. at 48,305–06 (Tables VIII.A–3, VIII.A–4); see 75 FR at 45,291 (Table IV.E–1), 45,309 (reflecting proposed annual emissions budgets for every Transport Rule State except Texas). With proper notice, Texas stakeholders would undoubtedly have pointed out that the single monitor to which the State was “significantly” linked was already in attainment status for the fine-particulate standard and was heavily influenced by a local steel mill. See 76 FR 29,652, 29,652–53 (May 23, 2011). And although EPA initially “requested comment on whether Texas should be included in the 29 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 43 of 52 Transport Rule for annual [fine particulate matter],” 76 FR at 48,214, it conceded that the sole basis for that request was irrelevant to EPA’s actual basis for including Texas in the final rule. See 75 FR at 45,284; JA1872. Interested parties could be expected to comment only on the monitors that the proposed rule linked to their home States—not on those that, under entirely different models, might be linked. Small Refiner, 705 F.2d at 549 (requiring reasonable specificity for the range of alternatives under consideration). States cannot be required to provide comments on the entire universe of air-quality monitors. See Fertilizer Inst. v. EPA, 935 F.2d 1303, 1311 (D.C. Cir. 1991) (explaining that notice-and-comment rulemaking is not a “guessing game” forcing conjecture on a subject that might be addressed). EPA also introduced a new “emissions leakage” methodology as a basis for determining significant contributions. 76 FR at 48,263. When modeled, emissions from Arkansas, Indiana, Louisiana, Maryland, and Mississippi were not found to significantly contribute to downwind nonattainment because those States had no cost-effective reductions available. Id. But EPA ultimately regulated the States based on ill-defined “interstate shifts in electricity generation that cause ‘emissions leakages.’” Id. This concept did not appear in the proposed rule. See id. Finally, whereas the proposed rule contemplated only one phase of reductions for “Group 2” sulfur-dioxide States, 75 FR at 45,216, the final rule 30 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 44 of 52 imposed two phases. 76 FR at 48,214. That change likewise fails the “logical outgrowth” test. EPA announced for the first time at finalization that Georgia’s 2014 sulfur-dioxide budget must drop significantly from 2012 to 2014 (even though the State had been moved out of “Group 1”) to prevent other sources from offsetting planned emissions reductions under non-Transport Rule requirements. Id. at 48,261. But the Court has been clear that switching to a new methodology in a final rule “does not advise interested parties how to direct their comments,” thus denying them adequate notice. Envtl. Integrity Project, 425 F.3d at 998. Individually and in combination, the States’ lack of notice requires vacatur. See id. C. EPA Lacked Authority To Promulgate Certain FIPs With Respect To The 2006 NAAQS.3 Transport Rule FIPs addressing the 2006 fine-particulate standard were signed by the EPA Administrator on July 6, 2011. See 76 FR at 48,353. Two weeks later, EPA published in the Federal Register disapprovals of good-neighbor SIPs submitted by Kansas, Indiana, and eight other States covered by the 2006 fineparticulate FIPs. See, e.g., 76 FR 43,143 (July 20, 2011). As the Supreme Court observed in Train v. NRDC, EPA “may devise and promulgate” a FIP “only if a State fails to submit [a SIP] which satisfies [the section-7410] standards.” 421 U.S. 3. This argument is presented on behalf of Kansas and Indiana only. 31 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 45 of 52 60, 79 (1975) (emphasis added). Because EPA’s FIP authority was never “triggered” under 42 U.S.C. 7410(c), the 2006 NAAQS FIPs promulgated for these ten states must be vacated. As the Supreme Court observed in EME Homer: “EPA’s FIP authority is triggered at the moment the Agency disapproves a SIP.” 134 S. Ct. at 1598. But the “moment” before EPA disapproves a SIP, its FIP rulemaking authority does not exist. From its inception in 1970, section 7410 has authorized EPA to initiate a FIP rulemaking only after EPA has taken final rulemaking action disapproving a submitted SIP. See, e.g., Train, 421 U.S. at 79; 42 U.S.C. 1857c-5(c)(1) (1970). In 1990, Congress extended the FIP-promulgation schedule from 120 days to 2 years, allowing States more time to resubmit SIPs that would cure the deficiencies identified by EPA in the SIP disapproval that triggered the FIP rulemaking. 42 U.S.C. 7410(c)(1). While this 1990 change did not address the proposal date for FIPs, nothing in the history of the amendment suggests that it was intended to change the state-federal SIP/FIP relationship to allow EPA to “devise” a FIP prior to disapproval of a SIP. As this Court has recognized, the 1990 “changes to section [74]10, at least as they concern EPA’s approval of [SIPs], … did not alter the division of responsibilities between EPA and the states in the section [74]10 32 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 46 of 52 process.” Virginia v. EPA, 108 F.3d 1397, 1409, 1410 (D.C. Cir. 1997). Accordingly, EPA’s action in promulgating these FIPs is contrary to section 7410(c). CONCLUSION The Court should vacate the Transport Rule in whole or part. Respectfully submitted, GREG ABBOTT Attorney General of Texas DANIEL T. HODGE First Assistant Attorney General JONATHAN F. MITCHELL Solicitor General JON NIERMANN Chief, Environmental Protection Division December 10, 2014 /s/ Bill Davis BILL DAVIS Assistant Solicitor General OFFICE OF THE ATTORNEY GENERAL P.O. Box 12548 (MC 059) Austin, Texas 78711-2548 Tel.: (512) 936-1896 Fax: (512) 370-9191 Bill.Davis@texasattorneygeneral.gov Counsel for Petitioners the State of Texas, the Public Utility Commission of Texas, the Railroad Commission of Texas, the Texas Commission on Environmental Quality, and the Texas General Land Office 33 USCA Case #11-1302 Document #1526530 Henry V. Nickel HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, NW Washington, DC 20037 Telephone: (202) 955-1561 Facsimile: (202) 788-2201 hnickel@hunton.com Filed: 12/10/2014 Page 47 of 52 Derek Schmidt Attorney General of Kansas Jeffrey A. Chanay Chief Deputy Attorney General OFFICE OF KANSAS ATTORNEY GENERAL DEREK SCHMIDT 120 SW 10th Avenue, 3rd Floor Topeka, KS 66612-1597 Telephone: (785) 368-8435 Facsimile: (785) 291-3767 jeff.chanay@ag.ks.gov George P. Sibley, III HUNTON & WILLIAMS LLP 951 E. Byrd Street Richmond, VA 23219 Telephone: (804) 788-8200 Facsimile: (804) 788-8218 gsibley@hunton.com Counsel for Petitioner State of Kansas Luther Strange Attorney General Robert D. Tambling Environmental Section STATE OF ALABAMA 501 Washington Ave. P.O. Box 300152 Montgomery, AL 36130-0152 Telephone: (334) 242-7300 Facsimile: (334) 242-2433 rtambling@ago.state.al.us Pamela Jo Bondi Attorney General of Florida Jonathan A. Glogau Chief, Complex Litigation OFFICE OF THE ATTORNEY GENERAL The Capitol, PL-01 Tallahassee, FL 32399-1050 Telephone: (850) 414-3817 Facsimile: (850) 414-9650 jon.glogau@myfloridalegal.com Counsel for Petitioner State of Florida Counsel for Petitioner State of Alabama 34 USCA Case #11-1302 Document #1526530 Samuel S. Olens Attorney General Isaac Byrd Deputy Attorney General John E. Hennelly Senior Assistant Attorney General James D. Coots Senior Assistant Attorney General GEORGIA DEPARTMENT OF LAW 40 Capitol Square, S.W. Atlanta, GA 30334-1300 Telephone: (404) 656-7542 Facsimile: (404) 651-6341 jcoots@law.ga.gov Filed: 12/10/2014 Page 48 of 52 Greg Zoeller Attorney General of Indiana Thomas M. Fisher Solicitor General of Indiana OFFICE OF THE ATTORNEY GENERAL Fifth Floor Indiana Government Center South 302 West Washington Street Indianapolis, IN 46204-2770 Telephone: (317) 232-6255 Facsimile: (317) 232-7979 tom.fisher@atg.in.gov Counsel for Petitioner State of Indiana Counsel for Petitioner State of Georgia James D. “Buddy” Caldwell Louisiana Attorney General Megan K. Terrell (LA# 29443) Assistant Attorney General LOUISIANA DEPARTMENT OF JUSTICE 1885 North Third Street Baton Rouge, LA 70802 Telephone: (225) 326-6085 Facsimile: (225) 326-6099 terrellm@ag.state.la.us David R. Taggart (LA# 12626) Jerald N. Jones (LA# 2005) BRADLEY MURCHISON KELLY & SHEA LLC 401 Edwards Street, Suite 1000 Shreveport, LA 71101 Telephone: (318) 227-1131 Facsimile: (318) 227-1141 dtaggart@bradleyfirm.com jjones@bradleyfirm.com Counsel for Petitioner State of Louisiana Special Counsel to Petitioner Louisiana Public Service Commission 35 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 49 of 52 LOUISIANA DEPARTMENT OF ENVIRONMENTAL QUALITY Herman Robinson (LA# 02077) Executive Counsel Jackie M. Marve (LA# 08241) Elliott Vega (LA# 21397) Donald Trahan (LA# 08493) Deidra Johnson (LA# 23501) Kathy M. Wright (LA# 30804) Legal Division Post Office Box 4302 Baton Rouge, LA 70821 Telephone: (225) 219-3985 Facsimile: (225) 219-4068 jackie.marve@la.gov Aaron D. Lindstrom Solicitor General of Michigan Neil David Gordon Assistant Attorney General Sean Peter Manning Chief, Environmental, Natural Resources, and Agriculture Division Brian J. Negele Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL State of Michigan 525 West Ottawa Street, 7th Floor P.O. Box 30212 Lansing, MI 48909 Telephone: (517) 373-3826 Facsimile: (517) 373-3042 Counsel for Petitioner Louisiana Department lindstroma@michigan.gov of Environmental Quality gordonn1@michigan.gov manningp@michigan.gov negeleb@michigan.gov Counsel for Petitioner State of Michigan 36 USCA Case #11-1302 Document #1526530 Harold E. Pizzetta, III Assistant Attorney General Chief, Civil Litigation Division OFFICE OF THE ATTORNEY GENERAL STATE OF MISSISSIPPI Post Office Box 220 Jackson, MS 39205 Telephone: (601) 359-3816 Facsimile: (601) 359-2003 hpizz@ago.state.ms.us Filed: 12/10/2014 Page 50 of 52 Jon C. Bruning Attorney General of Nebraska David D. Cookson Chief Deputy Attorney General Katherine J. Spohn Deputy Attorney General OFFICE OF THE ATTORNEY GENERAL 2115 State Capitol P.O. Box 98920 Lincoln, NE 68509-8920 Telephone: (402) 471-2834 Facsimile: (402) 471-2957 katie.spohn@nebraska.gov Counsel for Petitioner Mississippi Public Service Commission Counsel for Petitioner State of Nebraska Michael DeWine Attorney General of Ohio Dale T. Vitale Gregg H. Bachmann Elizabeth Ewing Assistant Attorneys General OFFICE OF THE ATTORNEY GENERAL 30 East Broad Street, 25th Floor Columbus, OH 43215-3428 Telephone (614) 466-2766 Facsimile: (614) 644-1926 dale.vitale@ohioattorneygeneral.gov gregg.bachmann@ohioattorneygeneral.gov elizabeth.ewing@ohioattorneygeneral.gov E. Scott Pruitt Attorney General of Oklahoma Patrick Wyrick Solicitor General P. Clayton Eubanks Deputy Solicitor General OFFICE OF THE OKLAHOMA ATTORNEY GENERAL 313 NE 21st Street Oklahoma City, OK 73105 Telephone: (405) 522-8992 Facsimile: (405) 522-0085 clayton.eubanks@oag.ok.gov patrick.wyrick@oag.ok.gov Counsel for Petitioner State of Ohio Counsel for Petitioner State of Oklahoma 37 USCA Case #11-1302 Document #1526530 Alan Wilson Attorney General of South Carolina Robert D. Cook Solicitor General James Emory Smith, Jr. Deputy Solicitor General OFFICE OF THE ATTORNEY GENERAL P.O. Box 11549 Columbia, SC 29211 Telephone: (803) 734-3680 Facsimile: (803) 734-3677 esmith@scag.gov Filed: 12/10/2014 Page 51 of 52 Leslie Sue Ritts THE RITTS LAW GROUP, PLLC 620 Fort Williams Parkway Alexandria, VA 22304 Telephone: (703) 823-2292 Facsimile: (571) 970-3721 lsritts@rittslawgroup.com Counsel for Petitioner City of Ames, Iowa Counsel for Petitioner State of South Carolina J.B. Van Hollen Attorney General of Wisconsin Thomas J. Dawson Assistant Attorney General State Bar #1016134 Maura F. Whelan Assistant Attorney General State Bar #1027974 WISCONSIN DEPARTMENT OF JUSTICE P.O. Box 7857 Madison, WI 53707-7858 Telephone: (608) 266-8987 Facsimile: (608) 266-2250 dawsontj@doj.state.wi.us whelanmf@doj.state.wi.us Counsel for Petitioner State of Wisconsin 38 USCA Case #11-1302 Document #1526530 Filed: 12/10/2014 Page 52 of 52 CERTIFICATE OF COMPLIANCE In accordance with Federal Rule of Appellate Procedure 32(a)(7) and D.C. Circuit Rule 32(a), I certify that this brief has been prepared in Microsoft Word using 14-point Equity typeface and is double-spaced (except for headings, footnotes, and block quotations). I further certify that the brief is proportionally spaced and contains 6,808 words, excluding the parts of the brief exempted by D.C. Circuit Rule 32(a)(1). The combined word count of the Industry and Labor Petitioners’ opening brief on remand and this brief does not exceed 14,000, as mandated by this Court’s October 23, 2014 order (Doc. No. 1518738). Microsoft Word was used to compute the word count. /s/ Bill Davis Bill Davis CERTIFICATE OF SERVICE On December 10, 2014, this brief was served via CM/ECF on all registered counsel. /s/ Bill Davis Bill Davis 39 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 ORAL ARGUMENT NOT YET SCHEDULED Page 1 of 177 No. 12-1100 (and consolidated cases) ______________________________________ IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT _______________________________________ WHITE STALLION ENERGY CENTER, LLC, et al., Petitioners, V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, et al., Respondents. ______________________________________ On Petition for Review of Final Agency Action 77 FR 9304 (Feb. 16, 2012) ______________________________________ JOINT BRIEF OF STATE, INDUSTRY, AND LABOR PETITIONERS ________________ Bill Schuette F. William Brownell Attorney General Lauren E. Freeman John J. Bursch Lee B. Zeugin Elizabeth L. Horner (Admitted only in Solicitor General S. Peter Manning VA; DC application pending) Neil D. Gordon HUNTON & WILLIAMS LLP Brian J. Negele 2200 Pennsylvania Avenue, N.W. Assistant Attorneys General Washington, D.C. 20037 Environment, Natural Resources, and (202) 955-1500 Agriculture Division bbrownell@hunton.com Office of the Attorney General of Counsel for Utility Air Regulatory Michigan Group 525 W. Ottawa Street P.O. Box 30755 Lansing, MI 48909 (517) 373-7540 manningp@michigan.gov gordonnl@michigan.gov negeleb@michigan.gov DATED: October 23, 2012 Counsel for the State of Michigan Additional counsel listed on following pages USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 2 of 177 Additional Counsel Peter S. Glaser George Y. Sugiyama Michael H. Higgins TROUTMAN SANDERS LLP 401 Ninth Street, N.W. Suite 1000 Washington, D.C. 20004 (202) 274-2998 peter.glaser@troutmansanders.com Luther Strange Attorney General State of Alabama Office of the Attorney General 501 Washington Avenue Montgomery, AL 36130 (334) 242-7445 Counsel for the State of Alabama Counsel for National Mining Association David B. Rivkin, Jr. Lee A. Casey Mark W. DeLaquil Andrew M. Grossman BAKER & HOSTETLER LLP Washington Square, Suite 1100 1050 Connecticut Avenue, N.W. Washington, D.C. 20036-5304 (202) 861-1500 drivkin@bakerlaw.com lcasey@bakerlaw.com mdelaquil@bakerlaw.com agrossman@bakerlaw.com Counsel for National Black Chamber of Commerce and Institute for Liberty Michael C. Geraghty Attorney General Steven E. Mulder State of Alaska 1031 W. 4th Avenue, Suite 200 Anchorage, AK 99501-1994 Counsel for the State of Alaska USCA Case #12-1100 Document #1401252 David M. Flannery Gale Lea Rubrecht Kathy G. Beckett Edward L. Kropp JACKSON KELLY PLLC 500 Lee Street, East, Suite 1600 P.O. Box 553 Charleston, WV 25322-553 (304) 340-1000 dmflannery@jacksonkelly.com galelea@jacksonkelly.com kbeckett@jacksonkelly.com skropp@jacksonkelly.com Filed: 10/23/2012 Page 3 of 177 Thomas Horne Arizona Attorney General Joseph P. Mikitish James T. Skardon Assistant Attorneys General Environmental Enforcement Section 1275 West Washington Phoenix, AZ 85007 (602) 542-8553 Joseph.mikitish@azag.gov Counsel for the State of Arizona Counsel for Midwest Ozone Group Leslie Sue Ritts RITTS LAW GROUP, PLLC The Carriage House 620 Fort Williams Parkway Alexandria, VA 22304 (703) 823-2292 LSRitts@rittslawgroup.com Counsel for American Public Power Association Dustin McDaniel Arkansas Attorney General Kendra Akin Jones Assistant Attorney General Charles L. Moulton Senior Assistant Attorney General Arkansas Attorney General 323 Center Street, Suite 400 Little Rock, AR 72201 (501) 682-2007 kendra.jones@arkansasag.gov charles.moulton@arkansasag.gov Counsel for the State of Arkansas, ex rel. Dustin McDaniel, Attorney General USCA Case #12-1100 Document #1401252 Peter S. Glaser George Y. Sugiyama Michael H. Higgins TROUTMAN SANDERS LLP 401 Ninth Street, N.W. Suite 1000 Washington, D.C. 20001 (202) 274-2998 peter.glaser@troutmansanders.com Counsel for Peabody Energy Corporation Filed: 10/23/2012 Page 4 of 177 Pamela Jo Bondi Attorney General of Florida Jonathan A. Glogau The Capitol, PL-01 Tallahassee, FL 32399-1050 Counsel for the State of Florida USCA Case #12-1100 Document #1401252 David M. Flannery Gale Lea Rubrecht Kathy G. Beckett Edward L. Kropp JACKSON KELLY PLLC 500 Lee Street, East, Suite 1600 P.O. Box 553 Charleston, WV 25322-553 (304) 340-1000 dmflannery@jacksonkelly.com galelea@jacksonkelly.com kbeckett@jacksonkelly.com skropp@jacksonkelly.com Counsel for West Virginia Chamber of Commerce, Inc., Georgia Association of Manufacturers, Inc., Indiana Chamber of Commerce, Inc., Indiana Coal Council, Inc., Kentucky Chamber of Commerce, Inc., Kentucky Coal Association, Inc., North Carolina Chamber, Ohio Chamber of Commerce, Pennsylvania Coal Association, South Carolina Chamber of Commerce, The Virginia Chamber of Commerce, The Virginia Coal Association, Incorporated, West Virginia Coal Association, Inc., and Wisconsin Industrial Energy Group, Inc. Filed: 10/23/2012 Page 5 of 177 Lawrence G. Wasden Idaho Attorney General PO Box 83720 Boise, ID 83720-0010 Counsel for the State of Idaho USCA Case #12-1100 Document #1401252 Grant Crandall Arthur Traynor, III UNITED MINE WORKERS OF AMERICA 18354 Quantico Gateway Drive Suite 200 Triangle, VA 22172 (703) 291-2457 gcrandall@umwa.org atraynor@umwa.org Eugene M. Trisko LAW OFFICES OF EUGENE M. TRISKO PO Box 47 Glenwood, MD 21738 (301) 639-5238 emtrisko@earthlink.net Counsel for United Mine Workers of America Filed: 10/23/2012 Page 6 of 177 Gregory F. Zoeller Indiana Attorney General Valerie Tachtiris Deputy Attorney General Office of the Attorney General IGC-South, Fifth Floor 302 West Washington St. Indianapolis, IN 46204 (317) 232-6290 Valerie.Tachtiris@atg.in.gov Counsel for the State of Indiana USCA Case #12-1100 Document #1401252 Dennis Lane STINSON MORRISON HECKER LLP 1775 Pennsylvania Ave., N.W., Suite 800 Washington, D.C. 20006-4605 (202) 785-9100 dlane@stinson.com Parthenia B. Evans STINSON MORRISON HECKER LLP 1201 Walnut Street, Suite 2900 Kansas City, Missouri 64106 (816) 842-8600 pevans@stinson.com Counsel for Kansas City Board of Public Utilities Filed: 10/23/2012 Page 7 of 177 Derek Schmidt Attorney General of Kansas Jeffrey A. Chanay Deputy Attorney General, Civil Litigation Division Office of the Attorney General of Kansas 120 SW 10th Avenue, 3rd Floor Topeka, KS 66612-1597 (785) 368-8435 jeff.chanay@ksag.org Henry V. Nickel HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, NW Washington, DC 20037 (202) 955-1500 hnickel@hunton.com George P. Sibley, III HUNTON & WILLIAMS LLP Riverfront Plaza, East Tower 951 E. Byrd Street Richmond, VA 23221 (804) 788-8200 gsibley@hunton.com Counsel for the State of Kansas USCA Case #12-1100 Document #1401252 Eric A. Groten VINSON & ELKINS LLP 2801 Via Fortuna, Suite 100 Austin, TX 78746-7568 (512) 542-8709 egroten@velaw.com Jeremy C. Marwell VINSON & ELKINS LLP 2200 Pennsylvania Avenue, NW Suite 500 West Washington, DC 20037-1701 (202) 639-6507 jmarwell@velaw.com Filed: 10/23/2012 Page 8 of 177 Harold E. Pizzetta III Assistant Attorney General Director, Civil Litigation Division 550 High Street, Suite 1100 Post Office Box 220 Jackson, MS 39205-0220 (601) 359-3816 hpizz@ago.state.ms.us Counsel for the State of Mississippi Counsel for White Stallion Energy Center, LLC John A. Riley Christopher C. Thiele BRACEWELL & GIULIANI LLP 111 Congress Avenue, Ste. 2300 Austin, TX 78701-4061 (512) 542-2108 john.riley@bgllp.com chris.thiele@bgllp.com Chris Koster Attorney General James R. Layton John K. McManus PO Box 899 Jefferson City, MO 65102 (573) 751-1800 James.Layton@ago.mo.gov Counsel for Chase Power Development, LLC Counsel for the State of Missouri USCA Case #12-1100 Document #1401252 Paul D. Clement Nathan A. Sales BANCROFT PLLC 1919 M Street, N.W., Suite 470 Washington, DC 20036 (202) 234-0090 pclement@bancroftpllc.com nsales@bancroftpllc.com Counsel for FirstEnergy Generation Corporation Filed: 10/23/2012 Page 9 of 177 Jon Bruning Attorney General of the State of Nebraska Katherine J. Spohn Special Counsel to the Attorney General 2115 State Capitol PO Box 98920 Lincoln, NE 68509 (402) 471-2682 Katie.spohn@nebraska.gov Counsel for the State of Nebraska Lisa Marie Jaeger BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 (202) 828-5800 lisa.jaeger@bgllp.com Counsel for Edgecombe Genco, LLC and Spruance Genco, LLC Wayne Stenehjem Attorney General State of North Dakota Margaret I. Olson Assistant Attorney General Office of Attorney General 500 North 9th Street Bismarck, ND 58501-4509 (701) 328-3640 maiolson@nd.gov Counsel for the State of North Dakota USCA Case #12-1100 Document #1401252 Steven C. Kohl Eugene E. Smary Sarah C. Lindsey WARNER NORCROSS & JUDD LLP 2000 Town Center, Suite 2700 Southfield, Michigan 48075-1318 (248) 784-5000 skohl@wnj.com Counsel for Wolverine Power Supply Cooperative, Inc. Filed: 10/23/2012 Page 10 of 177 Michael DeWine Attorney General of Ohio Dale T. Vitale Gregg H. Bachmann Cameron F. Simmons Assistant Attorneys General Environmental Enforcement Section 30 E. Broad St., 25th Floor Columbus, OH 43215-3400 (614) 466-2766 dale.vitale@ohioattorneygeneral.gov Counsel for the State of Ohio E. Scott Pruitt Oklahoma Attorney General P. Clayton Eubanks Assistant Attorney General Public Protection Unit/Environment Office of the Attorney General of Oklahoma 313 N.E. 21st Street Oklahoma City, OK 73105 (405) 522-8992 fc.docket@oag.ok.gov clayton.eubanks@oag.ok.gov Counsel for the State of Oklahoma James D. Schultz General Counsel Gregory E. Dunlap Senior Deputy General Counsel Robert M. Wolff Special Counsel Office of General Counsel 333 Market Street, 17th Floor Harrisburg, PA 17120 (717) 783-6563 Counsel for the Commonwealth of Pennsylvania USCA Case #12-1100 Document #1401252 Alan Wilson Attorney General James Emory Smith, Jr. Assistant Deputy Attorney General Office of the Attorney General P.O. Box 11549 Columbia, SC 29211 (803) 734-3680 agesmith@scag.gov Counsel for the State of South Carolina Filed: 10/23/2012 Page 11 of 177 Greg Abbott Attorney General of Texas Daniel T. Hodge First Assistant Attorney General John B. Scott Deputy Attorney General for Civil Litigation Jon Niermann Chief, Environmental Protection Division Mark Walters Assistant Attorney General Mary E. Smith Assistant Attorney General Office of the Attorney General of Texas Environmental Protection Division P. O. Box 12548, Capitol Station Austin, TX 78711-2548 (512) 463-2012 mark.walters@texasattorneygeneral.gov mary.smith@texasattorneygeneral.gov Counsel for the State of Texas, Texas Commission on Environmental Quality, Texas Public Utility Commission, and Railroad Commission of Texas Mark L. Shurtleff Utah Attorney General 350 North State Street, #230 Salt Lake City, UT 84114-2320 (801) 538-1191 Kenneth T. Cuccinelli, II Attorney General of Virginia 900 East Main Street Richmond, VA 23219 (804) 786-7240 Counsel for the State of Utah Counsel for the Commonwealth of Virginia USCA Case #12-1100 Document #1401252 Silas B. Taylor Senior Deputy Attorney General Office of the Attorney General of West Virginia State Capitol, Room 26-E Charleston, WV 25305 silastaylor@yahoo.com Counsel for the State of West Virginia Filed: 10/23/2012 Page 12 of 177 Gregory A. Phillips Wyoming Attorney General Jay A. Jerde Wyoming Deputy Attorney General Office of the Attorney General of Wyoming 123 State Capitol Cheyenne, WY 82002 (307) 777-7841 jay.jerde@wyo.gov Counsel for the State of Wyoming Brenna Findley 1007 East Grand Avenue Des Moines, IA 50319 brenna.findley@iowa.gov Jack Conway Attorney General of Kentucky 700 Capital Avenue, Suite 118 Frankfort, KY 40601 Counsel for Terry E. Branstad, Governor of the State of Iowa on behalf of the People of Iowa Counsel for Jack Conway, Attorney General of Kentucky Jeffrey R. Holmstead Sandra Y. Snyder BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 (202) 828-5800 Bart E. Cassidy Katherine L. Vaccaro MANKO, GOLD, KATCHER & FOX, LLP 401 City Avenue, Suite 500 Bala Cynwyd, PA 19004 (484) 430-5700 Counsel for Tri-State Generation and Transmission Association, Inc. Counsel for ARIPPA USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 13 of 177 CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES Pursuant to Circuit Rule 28(a)(1), State, Industry, and Labor Petitioners state as follows: A. Parties, Intervenors, and Amici Petitioners: Case No. 12-1100: White Stallion Energy Center, LLC Case No. 12-1101: National Mining Association Case No. 12-1102: National Black Chamber of Commerce and Institute for Liberty Case No. 12-1147: Utility Air Regulatory Group Case No. 12-1170: Eco Power Solutions (USA) Corporation (“Eco Power”). On October 10, 2012, Eco Power filed a motion for voluntary dismissal. Case No. 12-1172: Midwest Ozone Group Case No. 12-1173: American Public Power Association Case No. 12-1174: Julander Energy Company Case No. 12-1175: Peabody Energy Corporation Case No. 12-1176: Deseret Power Electric Cooperative Case No. 12-1177: Sunflower Electric Power Corporation Case No. 12-1178: Tri-State Generation and Transmission Association, Inc. Case No. 12-1180: Tenaska Trailblazer Partners, LLC i USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 14 of 177 Case No. 12-1181: ARIPPA Case No. 12-1182: West Virginia Chamber of Commerce Incorporated; Georgia Association of Manufacturers, Inc.; Indiana Chamber of Commerce, Inc.; Indiana Coal Council, Inc.; Kentucky Chamber of Commerce, Inc.; Kentucky Coal Association, Inc.; North Carolina Chamber; Ohio Chamber of Commerce; Pennsylvania Coal Association; South Carolina Chamber of Commerce; The Virginia Chamber of Commerce; The Virginia Coal Association, Incorporated; West Virginia Coal Association, Inc.; and Wisconsin Industrial Energy Group, Inc. Case No. 12-1183: United Mine Workers of America Case No. 12-1184: Power4Georgians, LLC Case No. 12-1185: State of Texas, Texas Commission on Environmental Quality, Texas Public Utility Commission, and Railroad Commission of Texas Case No. 12-1186: The Kansas City Board of Public Utilities – Unified Government of Wyandotte County/Kansas City, Kansas Case No. 12-1187: Oak Grove Management Company LLC Case No. 12-1188: Gulf Coast Lignite Coalition Case No. 12-1189: Puerto Rico Electric Power Authority Case No. 12-1190: State of Arkansas, ex rel. Dustin McDaniel, Attorney General Case No. 12-1191: Chase Power Development, LLC ii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 15 of 177 Case No. 12-1192: FirstEnergy Generation Corp. Case No. 12-1193: Edgecombe Genco, LLC; Spruance Genco, LLC Case No. 12-1194: Chesapeake Climate Action Network, Conservation Law Foundation, Environmental Integrity Project, and Sierra Club Case No. 12-1195: Wolverine Power Supply Cooperative, Inc. Case No. 12-1196: States of Michigan, Alabama, Alaska, Arizona, Florida, Idaho, Indiana, Kansas, Mississippi, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Carolina, Utah, West Virginia, Wyoming; Commonwealths of Pennsylvania and Virginia; Terry E. Branstad, Governor of the State of Iowa, on behalf of the People of Iowa; and Jack Conway, Attorney General of Kentucky Respondent: The U.S. Environmental Protection Agency is the Respondent in all of these cases. Lisa P. Jackson, Administrator, U.S. Environmental Protection Agency, is also named as a Respondent in Nos. 12-1174, 12-1189, and 12-1191. Intervenors: The Commonwealth of Massachusetts and the States of Connecticut, Delaware, Illinois, Iowa, Maine, Maryland, New Hampshire, New Mexico, New York, Rhode Island, Vermont and the District of Columbia and the City of New York are intervenor-respondents in No. 12-1100. iii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 16 of 177 The American Academy of Pediatrics, American Lung Association, American Nurses Association, American Public Health Association, Chesapeake Bay Foundation, Citizens for Pennsylvania’s Future, Clean Air Council, Conservation Law Foundation, Environment America, Environmental Defense Fund, Izaak Walton League of America, Natural Resources Council of Maine, Natural Resources Defense Council, Ohio Environmental Council, Physicians for Social Responsibility, Sierra Club, and Waterkeeper Alliance are intervenorrespondents in No. 12-1100. Calpine Corporation, Exelon Corporation, and Public Service Enterprise Group, Inc. are intervenor-respondents in No. 12-1100. The State of North Carolina is an intervenor-respondent in No. 12-1147. National Grid Generation LLC is an intervenor-respondent in No. 12-1147. Utility Air Regulatory Group and Oak Grove Management Company LLC are movant intervenor-respondents in Nos. 12-1170, 12-1174, and 12-1194. White Stallion Energy Center, LLC; Deseret Power Electric Cooperative; Sunflower Electric Power Corporation; Tri-State Generation and Transmission Association, Inc.; Tenaska Trailblazer Partners, LLC; and Power4Georgians, LLC are intervenor-respondents in No. 12-1174. Eco Power Solutions (USA) Corporation is an intervenor-respondent in No. 12-1194. iv USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 17 of 177 National Black Chamber of Commerce and Institute for Liberty are intervenor-respondents in No. 12-1194. Peabody Energy Corporation is an intervenor-respondent in Nos. 12-1174 and 12-1194. National Mining Association is an intervenor-respondent in Nos. 12-1174 and 12-1194. Sunflower Electric Power Corporation is an intervenor-respondent in No. 12-1194. Gulf Coast Lignite Coalition and Lignite Energy Council are intervenorrespondents in No. 12-1194. The States of California, Minnesota and Oregon, the County of Erie in the State of New York, the City of Baltimore in the State of Maryland, and the City of Chicago in the State of Illinois are intervenor-respondents in No. 12-1100. The National Association for the Advancement of Colored People are intervenor-respondents in No. 12-1100. White Stallion Energy Center, LLC is an intervenor-respondent in No. 121194. Chase Power Development, LLC is an intervenor-respondent in No. 121194. v USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 18 of 177 Amici: The Institute for Policy Integrity at New York University School of Law is an amicus curiae in support of respondent in No. 12-1100. The Chamber of Commerce of the United States of America is a movant amicus curiae in No. 12-1100. B. Rulings Under Review These petitions challenge EPA’s final rule, “National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units,” 77 FR 9304 (Feb. 16, 2012). C. Related Cases Each of the petitions for review consolidated under No. 12-1100 is related. These cases consist of Case Nos. 12-1101, 12-1102, 12-1147, 12-1172, 12-1173, 12-1175, 12-1176, 12-1177, 12-1178, 12-1180, 12-1181, 12-1182, 12-1183, 121184, 12-1185, 12-1186, 12-1187, 12-1188, 12-1189, 12-1190, 12-1191, 12-1192, 12-1193, 12-1195, and 12-1196. The consolidated cases on review have not previously been reviewed by this or any other Court. Case No. 12-1272—which focuses on two issues of the rule involving new units—was severed from the cases consolidated under Case No. 12-1100 on June 28, 2012. See Order Severing New Source Issues (Doc. No. 1381112). Briefing in vi USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 19 of 177 that case is currently being held in abeyance pending administrative reconsideration proceedings. See Order Holding Case in Abeyance (Doc. No. 1394140). Case No. 12-1166, which challenges the New Source Performance Standards (“NSPS”) issued in the same Federal Register notice as the rule under review in this case, was deconsolidated from Case No. 12-1100 on August 24, 2012. See Order Deconsolidating NSPS Issues (Doc. No. 1391295). Additionally, the NSPS issues in Case Nos. 12-1170 and 12-1185 were severed and assigned to a new docket, Case No. 12-1366, and consolidated with Case No. 12-1166. Id. vii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 20 of 177 CORPORATE DISCLOSURE STATEMENTS Industry and Labor Petitioners submit the following statements pursuant to Rule 26.1 of the Federal Rules of Appellate Procedure and Circuit Rule 26.1: American Public Power Association (“APPA”) is a nonprofit trade association, as defined under Circuit Rule 26.1(b), whose members are units of state and local governments that own and operate electric generating, distribution and transmission assets. APPA addresses issues of interest to its members, including those issues related to the development and implementation of requirements under federal and state Clean Air Act programs. APPA does not have any outstanding securities in the hands of the public, nor does APPA have a publicly owned parent, subsidiary, or affiliate. ARIPPA is a non-profit trade association that represents a membership primarily comprised of electric generating plants using environmentally-friendly circulating fluidized bed (“CFB”) boiler technology to convert coal refuse and/or other alternative fuels such as biomass into alternative energy and/or steam, with the resultant alkaline ash used to reclaim mine lands. ARIPPA was organized in 1988 for the purpose of promoting the professional, legislative and technical interests of its member facilities. ARIPPA has no outstanding shares or debt securities in the hands of the public and does not have any parent, subsidiary, or affiliate that has issued shares or debt securities to the public. Chase Power Development, LLC is a Texas limited liability company engaged in the development of electrical power generation facilities in Texas. Chase Power Development, LLC has no parent companies. Furthermore, no publicly held corporation has a 10 percent or greater ownership interest in Chase Power Development, LLC. Edgecombe Genco, LLC (“Edgecombe”) is a cogeneration facility that sells power by contract and produces steam for a steam host. No publicly held corporation owns any stock in Edgecombe. Edgecombe has issued no stock. Edgecombe is wholly-owned by Calypso Energy Holdings, LLC, which has issued no stock. FirstEnergy Generation Corporation is a wholly-owned subsidiary of FirstEnergy Solutions Corp. FirstEnergy Solutions Corp. is a wholly-owned viii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 21 of 177 subsidiary of FirstEnergy Corp., a diversified energy company whose ten electric utility operating companies comprise one of the nation’s largest investor-owned electric systems, serving customers in Maryland, New Jersey, Ohio, Pennsylvania, Virginia, and West Virginia. FirstEnergy Corp. is a publicly-held corporation incorporated under the laws of Ohio. No company owns more than 10 percent of the stock of FirstEnergy Corp. Georgia Association of Manufacturers, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. Indiana Chamber of Commerce, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. Indiana Coal Council, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. Institute for Liberty (“IFL”) is a non-profit and nonpartisan organization dedicated to defending the rights of individuals and businesses against undue encroachments by government that impair economic and civil liberties. It produces academic research on health, economic, and regulatory policy and, through its Center for American Regulatory Engagement, helps ordinary Americans participate in the regulatory process to ensure that their views are represented. IFL has no parent company, subsidiary, or affiliate that has issued shares or debt securities to the public. The Kansas City Board of Public Utilities-Unified Government Wyandotte County/Kansas City, Kansas is not required to provide a Corporate Disclosure Statement pursuant to Federal Rule of Appellate Procedure 26.1 because it is a governmental entity organized under the laws of the State of Kansas. Accordingly, no Corporate Disclosure Statement has been provided. Kentucky Chamber of Commerce, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. ix USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 22 of 177 Kentucky Coal Association, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. Midwest Ozone Group is an unincorporated association of businesses and organizations formed to assist in the development of scientifically sound and effective ozone strategies. Because it is a continuing association of numerous businesses and organizations operated for the purpose of promoting the general commercial and legislative interests of its membership, no listing of its members that have issued shares or debt securities to the public is required under Circuit Rule 26.1(b). National Black Chamber of Commerce (“NBCC”) is a non-profit, nonpartisan, nonsectarian organization dedicated to the economic empowerment of African American communities through entrepreneurship. Incorporated in 1993, it represents nearly 100,000 African American-owned businesses, and advocates on behalf of the one million Black-owned businesses in the United States. The Chamber has 190 affiliated chapters located throughout the nation. Members of the NBCC include companies that are substantial consumers of electricity and whose economic viability depends on affordable electric service. NBCC has no parent company, subsidiary, or affiliate that has issued shares or debt securities to the public. National Mining Association (“NMA”) is a non-profit, incorporated national trade association whose members include the producers of most of America's coal, metals, and industrial and agricultural minerals; manufacturers of mining and mineral processing machinery, equipment, and supplies; and engineering and consulting firms that serve the mining industry. NMA has no parent companies, subsidiaries, or affiliates that have issued shares or debt securities to the public, although NMA's individual members have done so. North Carolina Chamber is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. Ohio Chamber of Commerce is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. x USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 23 of 177 Peabody Energy Corporation is a publicly-traded company on the New York Stock Exchange (“NYSE”) under the symbol “BTU.” No public corporation owns more than 10% of Peabody's stock, with the exception of BlackRock, Inc. (NYSE: BLK), a publicly-held corporation which reported that as of December 31, 2011, it owned approximately 11.1% of Peabody's outstanding common stock. Peabody owns and operates several coal mines across the United States, and its coal production fuels approximately 10% of the nation's power generation. Pennsylvania Coal Association is an unincorporated trade association organized and existing under the laws of the Commonwealth of Pennsylvania. Because it is a continuing association of numerous businesses and organizations operated for the purpose of promoting the general commercial, professional, legislative, and other interests of its membership, no listing of its members that have issued shares or debt securities to the public is required under Circuit Rule 26.1(b). South Carolina Chamber of Commerce is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. Spruance Genco, LLC (“Spruance”) is a cogeneration facility that sells power by contract and produces steam for a steam host. No publicly held corporation owns any stock in Spruance. Spruance has issued no stock. Spruance is wholly-owned by Calypso Energy Holdings, LLC, which has issued no stock. Tri-State Generation & Transmission Association, Inc. (“Tri-State”) is a wholesale electric power supply cooperative which operates on a not-for-profit basis and is owned by 1.5 million member-owners and 44 distribution cooperatives. Tri-State issues no stock and has no parent corporation. Accordingly, no publicly held corporation owns 10% or more of its stock. United Mine Workers of America (“UMWA”) is a non-profit national labor organization with headquarters in Triangle, Virginia. Its members are active and retired miners engaged in the extraction of coal and other minerals in the United States and Canada, and workers in other industries in the United States organized by the UMWA. It provides collective bargaining representation and other membership services on behalf of its members. UMWA is affiliated with the American Federation of Labor-Congress of Industrial Organizations, and has no parent companies, subsidiaries, or affiliates that have issued shares or debt securities to the public. xi USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 24 of 177 Utility Air Regulatory Group (“UARG”) is a not-for-profit association of individual electric generating companies and national trade associations that participates on behalf of its members collectively in administrative proceedings under the Clean Air Act, and in litigation arising from those proceedings, that affect electric generators. UARG has no outstanding shares or debt securities in the hands of the public and has no parent company. No publicly held company has a 10% or greater ownership interest in UARG. The Virginia Chamber of Commerce is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. The Virginia Coal Association, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. West Virginia Chamber of Commerce is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. West Virginia Coal Association, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. White Stallion Energy Center, LLC (“White Stallion”) is a limited liability company organized under the laws of the State of Texas engaged in the business of energy development and production. White Stallion has no parent companies, and no publicly-held corporation has a 10% or greater ownership interest in it. Wisconsin Industrial Energy Group, Inc. is a not for profit corporation. It has no parent companies, subsidiaries or affiliates that have issued shares or debt securities to the public. Wolverine Power Supply Cooperative, Inc. (“Wolverine”) is a not-for-profit, member-owned, electric generation and transmission cooperative headquartered in Cadillac, Michigan. Wolverine has no parent company, and no publicly-held company has a 10% or greater ownership interest in Wolverine. xii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 25 of 177 TABLE OF CONTENTS CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES ..............i CORPORATE DISCLOSURE STATEMENTS ................................................... viii TABLE OF CONTENTS ....................................................................................... xiii TABLE OF AUTHORITIES ..................................................................................xvi GLOSSARY OF TERMS ................................................................................... xxvii PERTINENT STATUTES AND REGULATIONS .................................................. 1 STATEMENT OF JURISDICTION.......................................................................... 1 ISSUES PRESENTED FOR REVIEW ..................................................................... 1 INTRODUCTION ..................................................................................................... 3 STATEMENT OF THE CASE .................................................................................. 4 I. The Clean Air Act ................................................................................. 4 II. HAPs Emitted by EGUs ........................................................................ 7 III. A. Mercury ....................................................................................... 7 B. Non-Mercury Metal HAPs .......................................................... 9 C. Acid Gas HAPs ......................................................................... 10 D. Organic HAPs and Dioxin ........................................................ 10 EPA’s §112 Rulemaking ..................................................................... 11 A. The Utility Study....................................................................... 11 B. The December 2000 “Notice of Finding” ................................. 13 C. The §112(n) Rulemaking .......................................................... 14 D. New Jersey v. EPA .................................................................... 17 xiii USCA Case #12-1100 E. Document #1401252 Filed: 10/23/2012 Page 26 of 177 Remand Rulemaking ................................................................. 19 SUMMARY OF ARGUMENT ............................................................................... 22 STANDING ............................................................................................................. 23 STANDARD OF REVIEW ..................................................................................... 25 ARGUMENT ........................................................................................................... 25 I. II. EPA’s EGU MACT Standards Are Unlawful Under §112(n)(1)(A). ..................................................................................... 25 A. Because the Browner Finding Was Unlawful, the §112(d) EGU MACT Standards Must Be Vacated. ............................... 26 B. EPA’s Current Interpretations of §112(n)(1)(A) Are Unlawful.................................................................................... 29 C. EPA’s “Appropriate and Necessary” Determinations Are Unlawful.................................................................................... 48 Assuming Arguendo that the Requirements of §112(d) Govern the Validity of EPA’s EGU MACT Standards, Those Standards Are Unlawful Under §§112(c) and (d). ............................................... 55 A. EPA’s EGU MACT Standards Failed To Distinguish Between Major Sources and Area Sources. .............................. 55 B. The Mercury Standard for Existing Sources Is Arbitrary and Capricious........................................................................... 58 C. EPA Arbitrarily and Capriciously Refused To Set Alternative Health-Based Limits Under §112(d)(4) for Acid Gas HAPs. ........................................................................ 61 D. The Startup and Shutdown Work Practice Standards Were Promulgated with Inadequate Notice and Are Arbitrary and Capricious........................................................... 63 E. EPA’s Denial of UARG’s Delisting Petition Was Unlawful.................................................................................... 65 xiv USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 27 of 177 CONCLUSION ........................................................................................................ 66 CERTIFICATE OF COMPLIANCE CERTIFICATE OF SERVICE xv USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 28 of 177 TABLE OF AUTHORITIES FEDERAL CASES Ctr. for Energy & Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 2005) ................... 24 EME Homer City Generation, L.P. v. EPA, Nos. 11-1302 et al., 2012 WL 3570721 (D.C. Cir. Aug. 21, 2012) ..................................................15, 37 * Ethyl Corp. v. EPA, 51 F.3d 1053 (D.C. Cir. 1995) ............................................. 46 Fertilizer Inst. v. EPA, 935 F.2d 1303 (D.C. Cir. 1991).......................................... 64 Lujan v. Defenders of Wildlife, 504 U.S. 555 (1992) .............................................. 24 Mac’s Shell Serv., Inc. v. Shell Oil Prods. Co., 130 S. Ct. 1251 (2010) ................. 38 Mass. Trs. of E. Gas & Fuel Assocs. v. United States, 377 U.S. 235 (1964) ............................................................................................................. 33 Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000) ................................................... 41 * Motor Vehicle Mfrs. Ass’n v. State Farm Mutual Auto. Ins. Co., 463 U.S. 29 (1983)........................................................................25, 33, 50, 62, 63 Nat’l Asphalt Pavement Ass’n v. Train, 539 F.2d 775 (D.C. Cir. 1976) ................. 19 Nat’l Ass’n of Clean Air Agencies v. EPA, 489 F.3d 1221 (D.C. Cir. 2007) .............................................................................................................. 24 Nat’l Cable & Telecomms. Ass’n v. Brand X Internet Servs., 545 U.S. 967 (2005) ...................................................................................................... 33 Nat’l Lime Ass’n v. EPA, 233 F.3d 625 (D.C. Cir. 2000)..................................31, 32 * New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008) ........ 17, 18, 26, 27, 28, 31, 58 ______________________ * Authorities upon which we chiefly rely are marked with asterisks. xvi USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 29 of 177 North Carolina v. EPA, 531 F.3d 896, modified on reh’g, 550 F.3d 1176 (D.C. Cir. 2008) .................................................................................... 25 Norwest Bank Minn. Nat’l Ass’n. v. FDIC, 312 F.3d 447 (D.C. Cir. 2002) .............................................................................................................. 33 NRDC v. EPA, 824 F.2d 1146 (D.C. Cir. 1987) ...................................................... 41 PDK Labs., Inc. v. DEA, 362 F.3d 786 (D.C. Cir. 2004) ........................................ 34 * Prill v. NLRB, 755 F.2d 941 (D.C. Cir. 1985) ................................................25, 38 Radzanower v. Touche Ross & Co., 426 U.S. 148 (1976) ................................. 33, 34 Russello v. United States, 464 U.S. 16 (1983) ......................................................... 46 Schindler Elevator Corp. v. United States ex rel. Kirk, 131 S. Ct. 1885 (2011) ....................................................................................................... 39, 40 Sea-Land Serv., Inc. v. DOT, 137 F.3d 640 (D.C. Cir. 1998) ................................. 38 Sierra Club v. EPA, 167 F.3d 658 (D.C. Cir. 1999) ................................................ 61 Sierra Club v. EPA, 479 F.3d 875 (D.C. Cir. 2007) ................................................ 37 Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506 (D.C. Cir. 1983) ............................................................................................. 65 * Thomas v. New York, 802 F.2d 1443 (D.C. Cir. 1986) ...................................27, 28 Transitional Hosps. Corp. v. Shalala, 222 F.3d 1019 (D.C. Cir. 2000) ............ 34, 38 TVA v. EPA, 278 F.3d 1184 (11th Cir. 2002) .......................................................... 40 Whitman v. Am. Trucking Ass’ns, 531 U.S. 457 (2001) .......................................... 37 xvii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 30 of 177 FEDERAL STATUTES Clean Air Act, 42 U.S.C. §§ 7401 et seq. CAA § 101(b)(1), 42 U.S.C. § 7401(b)(1) .................................................... 30 CAA § 110(a)(2)(D), 42 U.S.C. § 7410(a)(2)(D) .............................15, 37, 50 CAA § 111, 42 U.S.C. § 7411 .................................................................16, 19 CAA § 111(b)(1)(A), 42 U.S.C. § 7411(b)(1)(A) ......................................... 48 CAA § 112, 42 U.S.C. § 7412 ..................... 1, 3, 4, 13, 14, 15, 16, 17, 22, 26, ................................................. 27, 29, 30, 31, 32, 35, 41, 45, 50, 53, 54 CAA § 112(a)(1), 42 U.S.C. § 7412(a)(1) ............................................... 32, 40 CAA § 112(a)(8), 42 U.S.C. § 7412(a)(8) ..................................................... 57 CAA § 112(b), 42 U.S.C. § 7412(b)................................................................ 6 CAA § 112(b)(2), 42 U.S.C. § 7412(b)(2) .................................................... 45 CAA § 112(c), 42 U.S.C. § 7412(c) ................................ 6, 14, 16, 17, 18, 20, ................................................................... 21, 26, 27, 29, 32, 40, 56, 65 CAA § 112(c)(1), 42 U.S.C. § 7412(c)(1) ............................................... 18, 32 CAA § 112(c)(3), 42 U.S.C. § 7412(c)(3) ............................................... 56, 58 CAA § 112(c)(6), 42 U.S.C. § 7412(c)(6) ..................................................... 57 CAA § 112(c)(9), 42 U.S.C. § 7412(c)(9) ..............................3, 17, 18, 23, 26, ......................................................................................34, 35, 52, 53, 65 CAA § 112(d), 42 U.S.C. § 7412(d)................ 2, 6, 18, 19, 21, 23, 26, 27, 29, ....................................................... 32, 36, 38, 40, 55, 56, 58, 61, 63, 66 xviii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 31 of 177 CAA § 112(d)(1), 42 U.S.C. § 7412(d)(1) .................................................... 57 CAA § 112(d)(3), 42 U.S.C. § 7412(d)(3) .................................................... 37 CAA § 112(d)(3)(A), 42 U.S.C. § 7412(d)(3)(A) ......................................... 58 CAA § 112(d)(4), 42 U.S.C. § 7412(d)(4) ..............................2, 23, 61, 62, 63 CAA § 112(e)(2)(A), 42 U.S.C. § 7412(e)(2)(A) ......................................... 45 CAA § 112(f), 42 U.S.C. § 7412(f) ............................................................... 34 CAA § 112(h), 42 U.S.C. § 7412(h)........................................................21, 63 CAA § 112(n), 42 U.S.C. § 7412(n)......................................16, 45, 46, 48, 55 CAA § 112(n)(1)(A), 42 U.S.C. § 7412(n)(1)(A) ......................1, 2, 3, 4, 6, 7, ................................................ 11, 13, 14, 18, 21, 22, 26, 27, 28, 29, 30, .......................................... 31, 32, 34, 35, 36, 37, 38, 39, 40, 41, 42, 44, ........................................... 45, 46, 47, 48, 52, 53, 54, 55, 56, 57, 58, 65 CAA § 112(n)(5), 42 U.S.C. § 7412(n)(5) .................................................... 45 CAA § 112(n)(6), 42 U.S.C. § 7412(n)(6) .................................................... 45 CAA § 115, 42 U.S.C. § 7415 ....................................................................... 28 CAA § 211(f)(4), 42 U.S.C. § 7545(f)(4)...................................................... 46 CAA § 307, 42 U.S.C. § 7607 ......................................................................... 1 CAA § 307(b), 42 U.S.C. § 7607(b).............................................................. 28 CAA § 307(b)(1), 42 U.S.C. § 7607(b)(1) ...................................................... 1 CAA § 307(d), 42 U.S.C. § 7607(d)........................................2, 14, 27, 28, 38 CAA § 307(d)(1)(C), 42 U.S.C. § 7607(d)(1)(C) .....................................7, 38 xix USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 32 of 177 CAA § 307(d)(9), 42 U.S.C. § 7607(d)(9) .................................................... 25 Clean Air Act Amendments of 1970, Pub. L. No. 91-604, § 112, 84 Stat. 1676, 1685 (1970) ............................................................................... 4, 5 LEGISLATIVE HISTORY 136 Cong. Rec. H12934 (daily ed. Oct. 26, 1990) (statement of Rep. Oxley), reprinted in 1 A LEGISLATIVE HISTORY OF THE CLEAN AIR ACT AMENDMENTS OF 1990 at 1416-17 (1998) ..........................31, 46, 48 Clean Air Act Amendments of 1990, Pub. L. No. 101-549 (1990), reprinted in 1 A LEGISLATIVE HISTORY OF THE CLEAN AIR ACT AMENDMENTS OF 1990 at 413, 572-73 (1998)................................................. 7 S. 1630 (1990), reprinted in 2 A LEGISLATIVE HISTORY OF THE CLEAN AIR ACT AMENDMENTS OF 1990 at 1809, 2148-49 (1998) .............................. 7 S. 1630, §301 (1990), reprinted in 3 A LEGISLATIVE HISTORY OF THE CLEAN AIR ACT AMENDMENTS OF 1990 at 4119, 4407, 4418-28 (1998)............................................................................................................... 6 S. Rep. No. 101-228 (1989), reprinted in 1990 U.S.C.C.A.N. 3385 ........................ 6 FEDERAL REGULATIONS 40 C.F.R. Part 61 ........................................................................................................ 5 40 C.F.R. Part 63, Subpart UUUUU, Table 3 ...................................................63, 64 40 C.F.R. § 63.2 ....................................................................................................... 63 40 C.F.R. § 63.10042 ............................................................................................... 63 xx USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 33 of 177 FEDERAL REGISTER 40 Fed. Reg. 48292 (Oct. 14, 1975)........................................................................... 5 48 Fed. Reg. 15076 (Apr. 6, 1983) ............................................................................ 5 48 Fed. Reg. 33112 (July 20, 1983) .......................................................................... 5 52 Fed. Reg. 8724 (Mar. 19, 1987) ............................................................................ 5 55 Fed. Reg. 39321 (Sept. 26, 1990) ....................................................................... 62 65 Fed. Reg. 79825 (Dec. 20, 2000) ......................................... 12, 13, 29, 31, 49, 66 67 Fed. Reg. 6521 (Feb. 12, 2002) ....................................................................14, 56 69 Fed. Reg. 4652 (Jan. 30, 2004) ...........................................................8, 15, 31, 37 70 Fed. Reg. 15994 (Mar. 29, 2005) .......................................... 9, 14, 15, 16, 17, 26, .................................................................................. 29, 31, 34, 39, 44, 49, 50 70 Fed. Reg. 28606 (May 18, 2005) ........................................................................ 16 76 Fed. Reg. 15554 (Mar. 21, 2011) ........................................................................ 57 76 Fed. Reg. 24976 (May 3, 2011) ...................................... 8, 10, 11, 21, 34, 39, 41, ............................................................................ 45, 47, 52, 53, 54, 59, 60, 63 77 Fed. Reg. 9304 (Feb. 16, 2012) ................................ 1, 20, 21, 22, 24, 26, 31, 32, ........................................................................... 33, 38, 40, 42, 43, 45, 47, 52, ............................................................................ 53, 54, 57, 59, 62, 63, 64, 65 MISCELLANEOUS Consent Decree, Am. Nurses Ass’n v. Johnson, No. 08-2198 (D.D.C. Apr. 15, 2010)................................................................................................ 20 xxi USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 34 of 177 Edgecombe Genco, LLC and Spruance Genco, LLC, Petition for Reconsideration of Final Rule; National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-CommercialInstitutional, and Small Industrial-Commercial-Institutional Steam Generating Units, 77 Fed. Reg. 9,304 (Feb. 16, 2012) (Apr. 27, 2012), EPA-HQ-OAR-2009-0234-20194 ..................................... 64 EPA, Information Collection Request for National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coaland Oil-Fired Electric Utility Steam Generating Units; Part B of the Supporting Statement (Dec. 24, 2009), EPA-HQ-OAR2009-0234-0103 ............................................................................................ 19 EPA, MATS ICR Data, MACT Floor Analysis – Coal HAP Metals, Spreadsheet a4_coal_pm_metal_mact_floor_analysis_121611. xlsx, Tab “Coal Metals Data” (Dec. 16, 2011), available at http://www.epa.gov/ttn/atw/utility/utilitypg.html ......................................... 52 EPA, Mercury Study Report to Congress, Vol. 1 (Dec. 1997), EPA– HQ–OAR–2009–0234–3054 ...................................................................11, 12 EPA, Non-Hg Case Study Chronic Inhalation Risk Assessment for the Utility MACT Appropriate and Necessary Analysis (Mar. 16, 2011), EPA-HQ-OAR-2009-0234-2939 (“EPA Non-Hg Case Study Memo”) .........................................................................................51, 52 EPA, Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards (Dec. 2011), EPA-HQ-OAR-2009-023420131 (“RIA”) .........................................................................................22, 51 EPA, Response to Comments Received on Proposed Information Collection Request (Published on July 02, 2009; 74 FR 31725), National Emission Standards for Hazardous Air Pollutants for Coal- and Oil-Fired Electric Utility Steam Generating Units (Nov. 5, 2009), EPA-HQ-OAR-2009-0234-0063 (“ICR RTC”) ............19, 59 xxii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 35 of 177 EPA, Responses to Public Comments on EPA’s National Emission Standards for Hazardous Air Pollutants from Coal- and OilFired Electric Utility Steam Generating Units, Vol. 1 (Dec. 2011), EPA-HQ-OAR-2009-0234-20126 (“RTC on Proposed Rule, Vol. 1”) ..........................................................................................61, 62 EPA, Responses to Public Comments on EPA’s National Emission Standards for Hazardous Air Pollutants from Coal- and OilFired Electric Utility Steam Generating Units, Vol. 2 (Dec. 2011), EPA-HQ-OAR-2009-0234-20126 (“RTC on Proposed Rule, Vol. 2”) ................................................................................................ 63 EPA, Responses to Significant Public Comments Concerning the Proposed Revision of the December 2000 Appropriate and Necessary Finding and the Proposed Removal of Utility Units from the Section 112(c) List (Mar. 15, 2005), EPA-HQ-OAR2002-0056-6193 ......................................................................................31, 32 EPA, Revised Technical Support Document: National-Scale Assessment of Mercury Risk to Populations with High Consumption of Self-caught Freshwater Fish; In Support of the Appropriate and Necessary Finding for Coal- and Oil-Fired Electric Generating Units (Dec. 2011), EPA-HQ-OAR-20090234-19913 (“Hg Risk TSD”) ....................................................................... 47 EPA, Risk Assessment Glossary, available at http://www.epa.gov/risk/glossary.htm (last updated July 31, 2012) .............................................................................................................. 12 EPA, Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units—Final Report to Congress, Vol. 1 (Feb. 1998), EPA-HQ-OAR-2009-0234-3052 (“Utility Study”) .......................................................................................8, 9, 10, 11, 12 EPA, Supplement to the Non-Hg Case Study Chronic Inhalation Risk Assessment in Support of the Appropriate and Necessary Finding for Coal- and Oil-Fired Electric Generating Units (Nov. 2011), EPA-HQ-OAR-2009-0234-19912 ........................................... 53 xxiii USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 36 of 177 EPRI, Comments on EPA Proposed Emission Standards/Proposed Standards of Performance, Electric Utility Steam Generating Units: Mercury Emissions (June 16, 2004), EPA-HQ-OAR2002-0056-2578 .............................................................................................. 9 EPRI, Comments on Proposed HAPS MACT Rule (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-17621 (“EPRI MATS Rule Comments”) .......................................................................................10, 51, 56 Joint Brief of Petitioners, Utility Air Regulatory Grp. v. EPA, No. 121166 (D.C. Cir. filed Oct. 23, 2012)........................................................63, 64 McCarthy, Gina, Assistant Adm’r, EPA, Letter to Lee Zeugin, Counsel for UARG (May 18, 2011), EPA-HQ-OAR-20090234-9859 ...................................................................................................... 20 MERRIAM-WEBSTER’S ONLINE DICTIONARY, available at http://www.merriam-webster.com/dictionary/appropriate (last visited Oct. 23, 2012) .................................................................................... 39 National Research Council, Toxicological Effects of Methylmercury (2000)............................................................................................................. 12 National Mining Association, Comments on Docket ID Numbers: EPA-HQ-OAR-2009-0234 (NESHAP action) and EPA-HQOAR-2011-0044 (NSPS), 76 Federal Register 24,976 (May 3, 2011) (Dec. 6, 2011), EPQ-HQ-OAR-2009-0234-19825 ............................. 23 NEW OXFORD AMERICAN DICTIONARY (2d ed. 2005) ............................................. 39 Newmont Nevada Energy Investment, LLC, Comments to the Proposed National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units, 76 Fed. Reg. 24976 (May 3, 2011) (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-17871 ..................................................... 56 Petition for a Writ of Certiorari, EPA v. New Jersey, No. 08-512 (U.S. Oct. 17, 2008) ................................................................................................ 44 xxiv USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 37 of 177 Shaver, Sally, EPA, Memorandum to Potential Petitioners Seeking Delisting of Hazardous Air Pollutants or Source Categories re: Information on EPA’s Delisting Process (undated) ...................................... 65 Southern Company, Comments on EPA’s Proposed National Emission Standards for Hazardous Air Pollutants from Coaland Oil-Fired Electric Utility Steam Generating Units; 76 Fed. Reg. 24976 (May 3, 2011) (Aug. 4, 2011), EPA-HQ-OAR2009-0234-18023 (“Southern Comments”) ............................................23, 51 Swackhammer, Deborah, Chair, Science Advisory Board , & Dr. Stephen M. Roberts, Chair, SAB Mercury Review Panel, Letter to Lisa P. Jackson, Adm’r, EPA (Sept. 29, 2011), EPA-SAB11-017 ............................................................................................................ 51 Texas Commission on Environmental Quality, Comments Regarding the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units; Proposed Rule (Aug. 4, 2011), EPA-HQ-OAR-20090234-18034 ..............................................................................................42, 43 Utility Air Regulatory Grp. v. EPA, No. 01-1074 (D.C. Cir. 2001) Petition for Review (Feb. 16, 2001) .............................................................. 14 EPA’s Motion to Dismiss (Apr. 9, 2001) ...................................................... 14 EPA’s Reply in Support of Motion to Dismiss (May 17, 2001) ................... 14 Order Granting Motions to Dismiss (July 26, 2001) ..................................... 14 UARG, Comments on National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units: Proposed Rule (Aug. 4, 2011), EPA-HQOAR-2009-0234-17775 (“UARG Comments”)...............................20, 51, 52, .....................................................................................................53, 60, 61, 62 xxv USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 38 of 177 UARG, Petition for Reconsideration of EPA's National Emission Standards for Hazardous Air Pollutants From Coal- and Oilfired Electric Utility Steam Generating Units: Proposed Rule (Apr. 16, 2012), EPA-HQ-OAR-2009-0234-20179 ..................................... 53 xxvi USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 GLOSSARY OF TERMS ACI Activated Carbon Injection Act Clean Air Act Agency U.S. Environmental Protection Agency BTU British Thermal Unit CAA Clean Air Act CAIR Clean Air Interstate Rule CAMR Clean Air Mercury Rule DSI Dry Sorbent Injection EGUs Electric Utility Steam Generating Units EPA U.S. Environmental Protection Agency GACT Generally Available Control Technology HAP Hazardous Air Pollutant HCl Hydrogen Chloride HF Hydrogen Fluoride Hg Mercury ICR Information Collection Request JA Joint Appendix MACT Maximum Achievable Control Technology MATS Mercury Air Toxics Standards xxvii Page 39 of 177 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 NAS National Academy of Sciences Ni Nickel OMB Office of Management and Budget RfC Reference Concentration RfD Reference Dose RIA Regulatory Impact Analysis RTC Response to Comments SAB Science Advisory Board tpy tons per year TSD Technical Support Document UARG Utility Air Regulatory Group xxviii Page 40 of 177 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 41 of 177 PERTINENT STATUTES AND REGULATIONS Clean Air Act (“CAA” or “Act”) §§112 and 307, 42 U.S.C. §§7412, 7607, 1 as well as relevant regulations, are reproduced in the attached Statutory and Regulatory Addendum. STATEMENT OF JURISDICTION The U.S. Environmental Protection Agency (“EPA” or “Agency”) published the “National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units,” on February 16, 2012 (“MATS rule”). 77 FR 9304 (Joint Appendix (“JA”)__). The consolidated petitions for review were filed on or before April 16, 2012. This Court has jurisdiction under CAA §307(b)(1). ISSUES PRESENTED FOR REVIEW 1. Whether the MATS rule must be vacated because the 2000 “appropriate and necessary” finding and source category listing based on that finding of coaland oil-fired electric utility steam generating units (“EGUs”) are unlawful. 2. Whether EPA’s §112(n)(1)(A) “appropriate and necessary” finding relies on statutory interpretations that are contrary to law and unreasonable. 1 Hereinafter only the CAA citation will be provided. The Table of Authorities provides parallel citations to the U.S. Code. USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 42 of 177 3. Whether EPA unlawfully failed to consider relevant statutory criteria, including regulatory costs, in making its “appropriate and necessary” finding. 4. Whether the record fails to support EPA’s §112(n)(1)(A) findings for emissions of mercury (“Hg”), other hazardous air pollutant (“HAP”) metals, and acid gas HAPs. 5. Assuming arguendo EPA’s §112(n)(1)(A) findings were lawful and had record support, whether EPA violated the CAA in promulgating §112(d) standards by: a. Not separately listing and regulating “major sources” and “area sources”; b. Using a flawed methodology to set the existing source mercury standard for EGUs burning high-British thermal unit (“BTU”) coal; and c. Refusing to promulgate alternative health-based limits under §112(d)(4). 6. Whether the work practice standards and associated definitions for startup and shutdown are arbitrary and capricious, and were promulgated in violation of §307(d)’s rulemaking requirements. 2 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 43 of 177 7. Whether EPA’s summary denial of the Utility Air Regulatory Group’s (“UARG”) §112(c)(9) delisting request was arbitrary and capricious and contrary to law. INTRODUCTION CAA §112 treats EGUs differently from other sources of HAP emissions. Historically, EPA recognized that there is little risk associated with HAP emissions from EGUs, particularly in light of other CAA programs that effectively control these emissions. Accordingly, Congress provided in §112(n)(1)(A) that EGUs are to be regulated under §112 only if, and to the extent that, EPA determines that EGU HAP emissions cause hazards to public health and that it is “appropriate and necessary” to regulate such emissions under §112. In 2005, EPA determined after extensive rulemaking that EGU HAP emissions do not cause hazards to public health and, therefore, that §112 regulation of EGU HAP emissions was neither appropriate nor necessary. Now, EPA would reverse that rulemaking determination and the statutory interpretations on which it was based, in order to regulate EGU emissions that, by EPA’s own analyses, pose no public health hazard. EPA’s new interpretations effectively deprive §112(n)(1)(A) of its meaning. EPA does this at an enormous cost to society by embracing the unnecessary type of EGU HAP regulation Congress sought to avoid, imposing annual compliance costs of $9.6 billion while producing a mere $4-5 3 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 44 of 177 million in benefits from HAP reductions. The resulting regulatory program is not “appropriate and necessary” and should be vacated. STATEMENT OF THE CASE In 1990, Congress directed that, when it comes to regulating HAPs, EGUs should be treated differently than all other sources. For most sources, Congress provided a rote formula: §112 regulation begins with categorizing sources, followed by rulemakings to set technology-based standards, and then follow-up rulemakings to address residual risks. For EGUs, §112 regulation is not rote. Regulation depends on whether additional reductions in HAP emissions are warranted given the substantial HAPs reductions resulting from other CAA requirements. For example, scrubbers installed to meet Acid Rain Program requirements are highly effective in reducing HAP emissions. Congress therefore directed EPA to determine whether remaining EGU HAP emissions pose a hazard to public health, study the efficacy and costs of further emission control for EGUs, and then decide, under CAA §112(n)(1)(A), whether and to what extent further regulation of EGU HAP emissions under §112 is “appropriate and necessary.” I. THE CLEAN AIR ACT Section 112, as enacted in 1970, Pub. L. No. 91-604, 84 Stat. 1676, 1685 (1970), required EPA to determine whether sources within an industrial category 4 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 45 of 177 released any HAP in amounts that were reasonably anticipated to result in “an increase in mortality or an increase in serious…illness,” and was to regulate those HAPs as necessary to protect public health with an “ample margin of safety.” CAA §112(a)(1) (1970). Under this provision, EPA regulated HAPs emitted from industrial source categories other than EGUs. See 40 C.F.R. Part 61. EGU HAP emissions are produced by the combustion of fossil fuels. These emissions are largely removed from the gas stream by control equipment installed to satisfy other CAA requirements. Under the 1970 and 1977 Acts, EPA investigated the need to regulate EGU HAP emissions, but never found such emissions posed unacceptable risk. For example, EPA found in 1975 and again in 1987 that “coal-fired power plants…do not emit mercury in such quantities that they are likely to cause the ambient mercury concentration to exceed” a level needed to “protect the public health with an ample margin of safety.” 40 FR 48292, 48297/2, 48298/1-2 (Oct. 14, 1975) (JA__); 52 FR 8724, 8725/3 (Mar. 19, 1987) (reaffirming mercury conclusion) (JA__); see also 48 FR 15076, 15085/3 (Apr. 6, 1983) (finding radionuclides from EGUs do not pose hazards to public health) (JA__). 2 EPA also set HAP standards for inorganic arsenic emissions without even mentioning EGUs, presumably because those sources did not release arsenic at levels that “result in significant risks.” See generally 48 FR 33112, 33116/1 (July 20, 1983). 2 5 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 46 of 177 In 1990, Congress concluded that this risk-based approach to HAP regulation was too time-consuming and cumbersome to implement. See S. Rep. No. 101-228, at 131-33 (1989), reprinted in 1990 U.S.C.C.A.N. 3385, 3516-18 (JA__). To solve this problem, Congress designated 189 HAPs under §112(b) and instructed EPA in §112(c) to list categories of “major” stationary sources of HAPs based on the amount emitted (10/25 tons). Listing triggered an obligation to establish technology-based emission standards under §112(d). These maximum achievable control technology (“MACT”) standards are based on the emissions reduction achieved in practice by the best controlled similar sources. EPA is also authorized to list and regulate non-major (i.e., “area”) sources separately under §112(c) and (d). By contrast, Congress provided in §112(n)(1)(A) that EGUs be treated differently. In S.1630, which the Senate passed on April 3, 1990, EGUs were to be listed under §112(c) and regulated under §112(d), like every other source category.3 When the House later passed a modified version of S.1630, it substantially changed the provisions governing EGUs, removing the requirement to list under §112(c) and regulate under §112(d). The House-passed provision, 3 See S.1630, §301 (1990), reprinted in 3 A Legislative History of the Clean Air Act Amendments of 1990 at 4119, 4407, 4418-28 (1998) (“1990 Legis. Hist.”) (JA__, __, __-__). 6 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 47 of 177 which was virtually identical to the current §112(n)(1)(A),4 was adopted by the Conference Committee and became law.5 Under §112(n)(1)(A), EPA must complete “a study of the hazards to public health reasonably anticipated to occur as a result of [EGU HAP] emissions” that remain after “imposition of the requirements of this [Act].” Id. (emphases added). As part of that evaluation, EPA must “develop and describe . . . alternative control strategies for [any HAP] emissions which may warrant regulation under this section.” Id. (emphases added). EGU HAP emissions can be regulated only to the extent that it is “appropriate and necessary after considering the results of the study.” Id. (emphasis added). Section 307(d)(1)(C) provides that the CAA’s notice-and-comment rulemaking requirements “appl[y] to…any regulation under section [112]…(n).” II. HAPS EMITTED BY EGUS Most HAP emissions from EGUs result from chemical elements that are naturally present in trace amounts in the fuels they burn. A. Mercury Mercury enters the environment through both natural processes, such as volcanic eruptions, evaporation of oceans, and forest fires, and human activities such as gold mining, municipal waste incineration, fossil fuel combustion, and 4 5 2 1990 Legis. Hist. at 2148-49 (JA__-__). 1 1990 Legis. Hist. at 572-73 (JA__-__). 7 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 48 of 177 chlorine manufacturing. Mercury is a global pollutant, meaning that a substantial percentage of mercury emissions circulates in the atmosphere for months before depositing on soil or in water.6 EPA has estimated that total global emissions of mercury are about 5,000 tons per year: 1,000 tons from natural sources, 2,000 tons from manmade sources, and 2,000 tons from reemission of previously deposited mercury into the ambient air.7 EPA’s 1998 Utility Study estimated that U.S. coal-fired EGUs emitted about 51.5 tons of mercury annually, or about 1% of the 5,000 tons of worldwide mercury emissions.8 By 2010, those mercury emissions were reduced to 29 tons per year (“tpy”).9 Humans are primarily exposed to mercury through consumption of fish containing methylmercury. 69 FR at 4658/1 (JA__). EGUs do not produce or emit methylmercury. Methylmercury is formed by microbes in the sediments of waterbodies, where it eventually works its way up the food chain to fish. Only a small fraction of the nine tons of domestic EGU mercury emissions deposited in EPA, Study of HAP Emissions from EGUs—Final Report to Congress, Vol. 1 at 7-7 (Feb. 1998), EPA-HQ-OAR-2009-0234-3052 (“Utility Study”) (JA__). 7 69 FR 4652, 4658/2-3 (Jan. 30, 2004) (JA__). 8 Utility Study at 7-8, Table 7-1 (JA__). 9 76 FR 24976, 25002/2 (May 3, 2011) (JA__). This more recent estimate reflects implementation of other CAA requirements. 6 8 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 49 of 177 the U.S.10 actually enters waterbodies, only a very small fraction of that deposition is biologically transformed into methylmercury, and only a small fraction of that methylmercury end up in fish that people eat. As a result, human exposure to methylmercury resulting from coal-fired EGUs is exceedingly small. 70 FR 15994, 16019-20 (Mar. 29, 2005) (JA__-___). B. Non-Mercury Metal HAPs Trace amounts of non-mercury metal HAPs—such as arsenic, chromium, and nickel—are naturally present in coal and oil. When these fuels are burned, metals adhere to the ash, becoming part of particulate matter. Virtually all of the particulate matter produced by EGUs is captured by high-efficiency control devices. In the Utility Study, EPA performed a conservative, “high-end” estimate of the inhalation risks posed by non-mercury metal emissions from all U.S. coal-fired EGUs. Those analyses showed that only two coal-fired facilities had cumulative risks from carcinogens of greater than one-in-one million from HAP metals. The highest facility had a risk of three-in-one million. Utility Study at 6-3, Table 6-1 (JA__). For non-carcinogen emissions, EPA found that exposure levels were far below the reference concentration (“RfC”). In December 2009, EPRI modeled 10 About 30% of U.S. EGU mercury emissions deposit within the continental United States. See EPRI, Comments on 2004 Proposed Rule at 2 (June 16, 2004), EPA-HQ-OAR-2002-0056-2578. 9 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 50 of 177 every coal-fired facility and confirmed that none posed a carcinogenic risk greater than one-in-one million.11 C. Acid Gas HAPs EGUs emit two acid gas HAPs: hydrogen chloride (“HCl”) and hydrogen fluoride (“HF”). During the combustion process, trace amounts of chlorine and fluorine found in coal and oil combine with hydrogen to form HCl and HF. HCl and HF are non-carcinogens, and EPA’s modeling has consistently shown that exposure of the maximum exposed individual to acid gas HAPs emitted by EGUs is an order of magnitude or more below the health-protective thresholds for those HAPs.12 D. Organic HAPs and Dioxin Coal and oil are mostly made up of “organic” compounds—i.e., molecules comprised mostly of carbon and hydrogen. These organics release a significant amount of energy when combusted and are the reason coal and oil are used as fuels. Organic HAPs can be emitted by EGUs as a result of incomplete EPRI, Comments on Proposed HAPs MACT Rule at 3-22 to 3-24 (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-17621 (“EPRI MATS Rule Comments”) (JA____). EPA recently conducted inhalation modeling that found five coal-fired facilities posed risks slightly greater than one-in-one million. As described in detail below, EPA’s recent modeling used contaminated emissions data. See infra Argument I.C.2. 12 See Utility Study at 6-7 (JA__); 76 FR at 25051/2 (“Our case study analyses of the chronic impacts of EGUs did not indicate any significant potential for them to cause any exceedances of the chronic RfC for HCl….”) (JA__). 11 10 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 51 of 177 combustion. Testing for organic HAPs and dioxins required by EPA in 2010 reported a large majority of non-detect values, meaning that these compounds are present in amounts too small to detect, if at all.13 III. EPA’S §112 RULEMAKING A. The Utility Study After enactment of the 1990 CAA, EPA began updating information on the types and amounts of HAPs emitted by EGUs. EPA also collected information on the health effects of those HAPs, and conducted modeling to determine how those emissions may affect public health. The products of these efforts were reported in the Mercury Study (December 1997)14 and the Utility Study (February 1998). The Utility Study did not contain a §112(n)(1)(A) “appropriate and necessary” determination. Utility Study, at ES-1 (JA__). Instead, EPA stated that it “believes that mercury from coal-fired utilities is the HAP of greatest potential concern” and that “[f]urther research and evaluation are needed to gain a better understanding of the risks and impacts of utility mercury emissions.” Id. at ES-27 (JA__). For three other HAPs, EPA noted “potential concerns and uncertainties that may need further study.”15 See 76 FR at 25040/1-2 (JA__). EPA, Mercury Study Report to Congress, Vol. 1 (Dec. 1997), EPA-HQOAR-2009-0234-3054 (“Mercury Study”) (JA__). 15 Id. For dioxin and arsenic emissions from coal-fired EGUs, EPA noted that screening studies “suggest…potential concern” but further evaluations were 13 14 11 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 52 of 177 After issuing the Utility Study, EPA undertook several efforts to advance its understanding of mercury health effects and of the quantity and form of mercury emissions from coal-fired EGUs.16 EPA asked the National Academy of Sciences (“NAS”) to review the toxicological effects of methylmercury and to recommend an appropriate reference dose (“RfD”).17 The NAS panel found that EPA’s RfD for methylmercury was “scientifically justifiable.”18 EPA also issued two information collection requests (“ICRs”). The first required all coal-fired EGUs to collect coal samples throughout 1999 and to analyze those samples for mercury content. 65 FR 79825, 79826/3 (Dec. 20, 2000) (JA__). The second required approximately 80 EGUs to conduct stack sampling of mercury emissions. Id. (JA__). EPA did not collect any further information about the three other HAPs it suggested may need further study. necessary to characterize their impacts. EPA also noted a “potential concern” about nickel emissions from oil-fired EGUs, but identified “significant uncertainties” about the form and health effects of those emissions. Id. 16 The Utility Study identified eleven areas where additional mercury research was needed. Utility Study at 14-8 to -9 (JA__-__). 17 EPA defines RfD as “[a]n estimate ... of a daily oral exposure to the human population (including sensitive subgroups) that is likely to be without appreciable risk of deleterious effects during a lifetime.” EPA, Risk Assessment Glossary, available at http://www.epa.gov/risk/glossary.htm (JA__). 18 National Research Council, Toxicological Effects of Methylmercury, at 11 (2000) (JA__). 12 USCA Case #12-1100 B. Document #1401252 Filed: 10/23/2012 Page 53 of 177 The December 2000 “Notice of Finding” On December 14, 2000, shortly before the Clinton Administration left office and well before EPA could complete the data collection and research on mercury it said was necessary to make a §112(n)(1)(A) determination, then-departing Administrator Browner published, without any prior notice of proposed rulemaking or opportunity to comment, a “notice of regulatory finding.” This notice announced her conclusions that regulation of mercury emissions from coalfired EGUs and nickel emissions from oil-fired EGUs was “appropriate and necessary” under §112. 65 FR at 79829/2 (JA__). The notice failed to identify the increment of mercury emissions that was “appropriate and necessary” to control under §112, and did not describe the “alternative control strategies for emissions which may warrant regulation under this section.” Indeed, Administrator Browner admitted that EPA could not at that time quantify the amount of methylmercury in U.S. fish attributable to mercury emissions from domestic coal-fired EGUs. Id. at 79827/2-3 (JA__). Administrator Browner claimed “it is unnecessary to solicit...public comment on today’s finding [because]…[t]he regulation developed subsequent to the finding will be subject to public review and comment.” Id. at 79831/1-2 (JA__). In that future rulemaking, she explained, EPA would consider alternative control strategies. Id. at 79830/3 (JA__). 13 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 54 of 177 UARG, one of the parties on this brief, sought review of the December 2000 notice in this Court.19 In response, EPA moved to dismiss, arguing that EPA’s actions were not final20 and would be “subject to further comment in subsequent rulemaking.”21 This Court granted EPA’s motion to dismiss, finding that “[t]his court…lacks jurisdiction at this time to review the determination of the Environmental Protection Agency…that regulation of coal- and oil-fired electric utility steam generating units is appropriate and necessary….”22 On February 12, 2002, EPA published in the Federal Register a notice under §112(c) listing coalfired boilers for regulation under §112 based on the 2000 notice of finding. 67 FR 6521 (Feb. 12, 2002) (JA__). C. The §112(n) Rulemaking In 2004, EPA initiated a rulemaking, following the requirements of §307(d), to address HAP emissions from coal- and oil-fired EGUs. EPA considered a number of regulatory options, including: (1) no further regulation of EGU mercury emissions; (2) adoption of a §112(d) rule regulating only EGU mercury emissions; (3) adoption of rules under §112(n)(1)(A) addressing any EGU emissions that Utility Air Regulatory Grp. v. EPA, No. 01-1074 (D.C. Cir. filed Feb. 16, 2001) (“UARG v. EPA”). 20 EPA’s Motion to Dismiss at 1, UARG v. EPA (Apr. 9, 2001) (JA__). 21 Id. at 9 (JA__); see also EPA’s Reply in Support of Motion to Dismiss at 4, UARG v. EPA (May 17, 2001) (“the entire predicate for EPA’s finding determination and listing decision (both legal and factual) is susceptible to further comment and administrative review”) (JA__); 70 FR at 15996/2-3 (JA__). 22 Order at 1, UARG v. EPA, (July 26, 2001) (JA__). 19 14 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 55 of 177 warrant regulation as “appropriate and necessary”; and (4) adoption of rules under other CAA sections that make further control inappropriate and unnecessary under §112.23 EPA completed detailed scientific and technical studies to address data gaps identified by the Utility Study. Commenters also submitted detailed technical information on EGU mercury emissions and their health consequences. EPA conducted extensive modeling to analyze how changes in mercury emissions from coal-fired EGUs, including total elimination of those emissions, would affect U.S. mercury deposition and methylmercury levels in fish.24 The modeling showed that only a small fraction of the mercury deposited in the U.S. comes from domestic EGUs, and that EGUs contribute a “relatively small percentage” to fish tissue methylmercury levels in the U.S.25 as a result of implementation of other CAA requirements, including the Clean Air Interstate Rule (“CAIR”). See 70 FR at 16004/2 (JA__).26 On March 29, 2005, EPA concluded its rulemaking. Regarding mercury, EPA found that “[b]ecause this new information demonstrates that the level of Hg emissions projected to remain ‘after imposition of’ section 110(a)(2)(D) does not cause hazards to public health, we conclude that it is not appropriate to regulate See 69 FR at 4652 (JA__). 70 FR at 16011-25 (summarizing EPA’s modeling) (JA__-__). 25 Id. at 16019-20 (JA__-___) (on average about 4%). 26 CAIR was remanded to EPA by this Court and remains in place pending replacement rulemaking. EME Homer City Generation, L.P. v. EPA, Nos. 11-1302 et al., 2012 WL 3570721, at *24 (D.C. Cir. Aug. 21, 2012). 23 24 15 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 56 of 177 coal-fired Utility Units under §112 on the basis of mercury emissions.” Id. EPA similarly concluded that regulation of nickel emissions from oil-fired EGUs was neither “appropriate” nor “necessary.” Id. at 16007/2-08/2 (JA__-__). EPA further found, as it had under the 1970 and 1977 Acts, that EGU emissions of nonmercury HAPs were too small to warrant regulation. Id. at 16006/2-3 (JA__-__). Because EPA found that the December 2000 notice “lacked foundation” and because §112 regulation was neither appropriate nor necessary, there was no longer a predicate for listing EGUs. Therefore, EPA removed EGUs from the §112(c) list. Id. at 15994/1-2 (JA__). EPA proceeded to regulate mercury emissions from EGUs under §111 through the Clean Air Mercury Rule (“CAMR”) as a backstop to ensure that expected mercury emissions reductions under CAIR would occur. 70 FR 28606 (May 18, 2005) (JA__).27 In this rulemaking, EPA announced its key interpretations of §112(n). EPA cited the Merriam-Webster dictionary definition of “appropriate” as meaning “especially suitable or compatible.” 70 FR 16000/3 (JA__). In deciding whether regulation of EGUs was “appropriate,” EPA asked whether the remaining HAP emissions from EGUs, after imposition of other CAA requirements, resulted in hazards to public health. If they do not, EPA said that it would not be “‘especially suitable’ -- i.e., ‘appropriate’ -- to regulate such units under section 112.” Id. 27 EPA asserted that imposition of CAMR provided independent justification for not regulating coal-fired EGUs under §112. 70 FR at 16004/2 (JA__). 16 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 57 of 177 (JA__). EPA interpreted the term “necessary” to mean “that it is necessary to regulate Utility Units under section 112 only if there are no other authorities available under the CAA that would, if implemented, effectively address the remaining HAP emissions from Utility Units.” Id. at 16001/2 (JA__). EPA also interpreted these terms to include consideration of regulatory and compliance costs. Id. at 16001/1 n.19 (JA__). D. New Jersey v. EPA Numerous parties challenged EPA’s revision rule and CAMR. After all of the issues regarding these two rules were briefed, this Court limited oral argument to a single issue—whether EPA erred in removing EGUs from the §112(c) list of major source categories of HAP emissions. On February 8, 2008, the Court vacated EPA’s decision to remove EGUs from the list and also vacated CAMR. New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). The Court held that, once listed, the only way that a source category may be removed from the §112(c) list is by making the showings required by §112(c)(9). Id. at 581-82. Because EPA did not follow §112(c)(9), the court vacated the rule. Id. at 583. The Court did not rule on whether EPA’s December 2000 appropriate and necessary determination and subsequent listing decision were legally correct, whether they were supported by the factual record, whether EPA followed the proper procedural steps in taking its December 2000 actions, whether EPA’s 2005 17 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 58 of 177 legal interpretation of §112(n)(1)(A) was correct, or whether EPA’s 2005 factual findings were correct. The Court’s only discussion of §112(n)(1)(A) was limited to responding to EPA’s argument that an agency has inherent authority to reverse an earlier administrative determination where it has a principled basis for doing so. The Court stated: “An agency can normally change its position and reverse a decision, and prior to EPA’s listing of EGUs under section 112(c)(1), nothing in the CAA would have prevented it from reversing its [§112(n)(1)(A)] determination about whether it was ‘appropriate and necessary’ to do so.” (emphasis added). Id. at 582-83 But, once the nonfinal, unreviewable “appropriate and necessary” finding was followed by a nonfinal, unreviewable §112(c) listing decision, the Court said EPA was required by statute to propose and promulgate §112(d) standards for EGUs unless, prior to that promulgation, EPA delisted EGUs in accordance with §112(c)(9). Id. at 582. In sum, the Court in New Jersey saw no difference between delisting a properly listed source category pursuant to §112(c)(9) and administratively correcting an improper listing decision through removal of the category from the list (as EPA had done in the past when it found that a listed “major source” category did not include “major sources”).28 While, listing decisions therefore could not be corrected administratively, EPA’s listing decision would be reviewable following promulgation of §112(d) standards. See 28 New Jersey, 517 F.3d at 583 (citing respondent’s brief). 18 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 59 of 177 Nat’l Asphalt Pavement Ass’n v. Train, 539 F.2d 775, 779 n.1 (D.C. Cir. 1976) (threshold finding under §111 is reviewable in judicial challenge of final standards). E. Remand Rulemaking On remand, EPA issued an ICR in two phases to update mercury emissions information and obtain extensive new emissions information on all other HAPs emitted by the “best performing” EGUs.29 This December 2009 ICR required every EGU to provide detailed information on plant equipment and operations, obtain 12 months of data about the source and chemical constituents of each coal and oil shipment, and provide all emissions tests conducted since January 1, 2005. In the second phase of the ICR, 492 well-controlled EGUs were required to conduct stack testing for one or more HAP groupings within eight months30—a schedule that foreclosed retesting of suspect results. EGUs spent over $100 million to comply with the ICR. After completion of ICR responses in September 2010, there was little time under EPA’s consented-to rulemaking schedule31 to review and analyze this 29 EPA, Response to Comments on Proposed ICR at 26 (Nov. 5, 2009), EPA-HQ-OAR-2009-0234-0063 (JA__) (“ICR RTC”). 30 EPA, ICR Supporting Statement Part B (Dec. 24, 2009), EPA-HQ-OAR2009-0234-0103 (JA__). EPA identified five HAP “groups” for testing: mercury, non-mercury metals, acid gases, organics and dioxins. 31 Following the New Jersey decision, and before EPA could complete the §112(d) MACT rulemaking (i.e., the subject of this litigation), the U.S. District 19 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 60 of 177 mountain of data before drafting a proposed rule. This rushed process produced significant anomalies. For example, within days of publishing the proposed rule, UARG alerted EPA that it had divided mercury emissions data expressed in lb/GWh by a factor of 1,000,000, instead of the correct divisor of 1,000, to derive a proposed mercury emission standard expressed in lb/MWh. This resulted in a proposed rule based on mercury emissions that were calculated to be 1,000 times lower than the actual data, which in turn led to miscalculation of the average level of mercury control achieved by the best units and misidentification of the “best performing” units. See UARG Comments on Proposed MATS Rule at 89-90 (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-17775 (“UARG Comments”) (JA_____). In a letter to UARG, EPA admitted its error,32 but did not issue a new proposal. The public was left to evaluate and to comment on a seriously flawed rule. EPA published the MATS rule on February 16, 2012. In that rule, EPA concluded that its 2000 “appropriate and necessary” finding was valid when made, and constituted a sufficient basis for its 2002 action listing EGUs under §112(c). 77 FR at 9320/1 (JA__). EPA also asserted that newer information established that Court for the District of Columbia entered a consent decree imposing a compressed rulemaking schedule. Am. Nurses Ass’n v. Johnson, No. 08-2198 (D.D.C. Apr. 15, 2010) (JA__). 32 Letter from Gina McCarthy, EPA Assistant Adm’r, to Lee Zeugin, Counsel for UARG, at 1 (May 18, 2011), EPA-HQ-OAR-2009-0234-9859 (JA__). 20 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 61 of 177 (i) EGU mercury emissions pose a public health hazard, (ii) utility emissions of non-mercury HAP metals pose a health and environmental threat, and (iii) acid gas EGU HAP emissions pose an environmental threat. 77 FR at 9362-64 (JA__-__). For non-mercury HAP metals, this newer information consisted of a 16-unit case study that EPA conducted immediately before issuing the proposal. 76 FR at 25011/3-12/2 (JA__-__). There was no new EPA study of EGU acid gas impacts, but rather a single literature citation to a 2011 journal article about acid gas deposition in the United Kingdom. 77 FR at 9361/3-62/1 (JA__-__). Based on these findings, EPA rejected comments calling for it to affirm the 2005 rulemaking determination that the 2000 “appropriate and necessary” finding should not have been made, and that EPA should not have listed EGUs under §112(c). In doing so, EPA abandoned virtually all the 2005 rulemaking interpretations of §112(n)(1)(A). EPA then proceeded to issue §112(d) emission limits for EGU mercury, non-mercury HAP metals, and acid gas emissions, and §112(h) work practice standards for organic substance emissions. According to EPA analyses, it will be extraordinarily expensive to comply with the rule (about $9.6 billion per year), even though its health benefits were extraordinarily low (just $4-6 million, all from reducing mercury). See 77 FR at 9428/3 (JA__). Significant costs stem from compliance requirements for acid gases, even though EPA concluded EGU acid gas emissions pose no health risk, 21 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 62 of 177 and even though it could not quantify any environmental risk associated with such emissions.33 While EPA asserted that the rule was nonetheless cost-effective based on “co-benefits” of reducing PM2.5 emissions—a non-HAP substance addressed under other CAA programs—EPA emphatically maintained that these PM2.5 cobenefits played no role in its “appropriate and necessary” finding. 77 FR at 9320/1 (JA__). SUMMARY OF ARGUMENT Before undertaking any regulation of EGUs under §112, EPA must study the “public health [hazards] reasonably anticipated to occur as a result of emissions” of HAPs from EGUs. §112(n)(1)(A). If health hazards are identified, the Administrator may regulate a specific EGU HAP only “if the Administrator finds that such regulation is appropriate and necessary.” Id. The MATS rule must be set aside because the 2002 listing of EGUs was based on a substantively and procedurally flawed December 2000 “appropriate and necessary” finding. Even if the Court finds that EPA could augment its 2000 finding in the later 2012 rulemaking, that rulemaking does not establish that it is “appropriate and necessary” to regulate EGUs under §112. The 2012 rulemaking fails to justify EPA’s departure from its 2005 rulemaking interpretations of §112(n)(1)(A). See EPA, Regulatory Impact Analysis for Final MATS at 3-15, Figure 3.6 (Dec. 2011), EPA-HQ-OAR-2009-0234-20131 (“RIA”) (JA__). Flue gas desulfurization and dry sorbent injection (“DSI”) costs are driven by acid gas standards. 33 22 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 63 of 177 Further, EPA’s new interpretations are both inconsistent with the CAA and unreasonable. Finally, the record does not support EPA’s findings that mercury, non-mercury HAP metals, and acid gas HAPs pose public health hazards. While those fatal defects should end the matter, even if the Court were to accept EPA’s “appropriate and necessary” analysis, the promulgated §112(d) EGU MACT standards must still be set aside for several independent reasons. First, contrary to explicit statutory directives, EPA did not distinguish between “major sources” and “area sources.” Second, EPA used a flawed methodology to set the mercury standard for existing sources that combust high-BTU coal. Third, EPA arbitrarily refused to set §112(d)(4) standards for acid gases. Fourth, the work practice standards and associated definitions promulgated in the final rule are procedurally deficient because EPA failed to provide an opportunity for public comment. Finally, EPA’s summary denial of UARG’s §112(c)(9) delisting request was arbitrary and capricious and based on flawed statutory interpretation. STANDING Industry and Labor Petitioners will suffer concrete, particularized injury as a result of the direct regulation of EGUs. See, e.g. Southern Company, Comments on Proposed Rule at 1-2, 9-12 (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-18023 (“Southern Comments”) (JA__-__, __-__); National Mining Association, Comments on Proposed Rule at 1-2 (Dec. 6, 2011), EPA-HQ-OAR-2009-0234- 23 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 64 of 177 19825 (JA__-__). The relief requested by Industry and Labor Petitioners will redress these harms. These Petitioners have Article III standing. See, e.g., Lujan v. Defenders of Wildlife, 504 U.S. 555, 561-63 (1992); Ctr. for Energy & Econ. Dev. v. EPA, 398 F.3d 653, 656-58 (D.C. Cir. 2005). Likewise, State Petitioners satisfy the Article III standing requirements of injury, causation, and redressability. See Lujan, 504 U.S. at 560-61. Among other things, States have standing to challenge rules that make their regulatory tasks more difficult. See Nat’l Ass’n of Clean Air Agencies v. EPA, 489 F.3d 1221, 1228 (D.C. Cir. 2007). For example, State public utility commissions, which are responsible for maintaining the reliability and continuity of each State’s electricity grid, face increased regulatory challenges as the costs of complying with the MATS rule force some EGUs out of the energy market, contributing to the widespread retirement of the Nation’s coal-fired generating capacity. See 77 FR at 9407/3 (JA__). This loss in generating capacity will complicate State Petitioners’ vital task of keeping the lights on, requiring public utility commissions to manage a dwindling supply of electricity and to increase prices. Beyond the regulatory burden on States, the annual compliance cost of the rule will be $9.6 billion in 2015, which will be borne by affected sources or passed on to consumers (including the States) through higher electricity costs. See 77 FR at 9425/1 (JA__). 24 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 65 of 177 By setting aside the MATS rule, this Court would prevent these costs and redress the harm suffered by State Petitioners. STANDARD OF REVIEW CAA §307(d)(9) requires this Court to strike down EPA action that is “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” Agency action is arbitrary and capricious where EPA “relied on factors which Congress has not intended it to consider, entirely failed to consider an important aspect of the problem, offered an explanation for its decision that runs counter to the evidence before the agency, or is so implausible that it could not be ascribed to a difference in view or the product of agency expertise.” North Carolina v. EPA, 531 F.3d 896, 906 (citation and quotation marks omitted), modified on reh’g, 550 F.3d 1176 (D.C. Cir. 2008); Motor Vehicle Mfrs. Ass’n v. State Farm Mutual Auto. Ins. Co., 463 U.S. 29, 43 (1983); see also Prill v. NLRB, 755 F.2d 941, 947-48 (D.C. Cir. 1985). ARGUMENT I. EPA’S EGU MACT STANDARDS ARE UNLAWFUL UNDER §112(n)(1)(A). Congress directed EPA to regulate EGUs only to the extent “appropriate and necessary” after considering other CAA requirements. While EPA recognized that 25 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 66 of 177 “Congress treated Utility Units differently from other major and area sources…,”34 EPA’s interpretation and implementation of §112(n)(1)(A) here effectively eliminate this distinction, contrary to the language and structure of §112. A. Because the Browner Finding Was Unlawful, the §112(d) EGU MACT Standards Must Be Vacated. A valid listing decision under §112(c) is the legal predicate for promulgating any §112(d) standards. In the case of EGUs, assuming for purposes of argument that EPA may elect to regulate under §112, EPA’s §112(c) listing would require a lawful “appropriate and necessary” finding under §112(n)(1)(A). New Jersey, 517 F.3d at 582. While an agency generally may correct an erroneous threshold finding, this Court in New Jersey found that, absent a §112(c)(9) delisting determination, §112(c) does not allow EPA to correct an erroneous §112(n)(1)(A) (or even an erroneous “major” source) threshold finding administratively. Instead, according to the Court, EPA must proceed to final promulgation of §112(d) standards and only this Court may “correct” an erroneous §112(n)(1)(A) decision after promulgation of §112(d) standards. As the New Jersey Court held, on review of those standards, the Court must determine whether the listing predicates for those 34 70 FR at 15997/2 (JA__); see also 77 FR at 9333/3 (acknowledging that “disparate treatment” of EGUs under §112) (JA__). 26 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 67 of 177 standards were lawful and, if not, “correct” that flaw through vacatur of the standards. Id. at 583. EPA added EGUs to the §112(c) list of source categories in 2002, based on Administrator’s December 2000 §112(n)(1)(A) notice. As this Court explained in New Jersey, once the Administrator issued a notice in 2000 that EGUs should be regulated under §112 and then listed EGUs, the statute “prevented it [EPA] from reversing its determination about whether it was ‘appropriate and necessary’ to do so.” Id. at 582-83. EPA did not purport in the instant rulemaking to renew the earlier listing of EGUs. Therefore, as a consequence of New Jersey, the validity of the 2002 listing decision must be judged in reference to the validity of the 2000 §112(n)(1)(A) notice of finding on which it was based; if that finding was unlawful, the listing was unlawful. The record plainly shows that when EPA issued its December 2000 notice, it had not undertaken a §112(n)(1)(A) rulemaking, as required under §307(d). Nor had EPA undertaken the work needed to characterize mercury health risks. See supra p.13. Therefore, the December 2000 notice was a fundamentally flawed threshold finding that could have no legal consequences and could not lawfully impose future obligations on EPA to regulate under §112(d). In Thomas v. New York, 802 F.2d 1443 (D.C. Cir. 1986), this Court held that only a “threshold” finding embodied in a legislative rule can compel future agency 27 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 68 of 177 action. In Thomas, this Court addressed whether a letter, in which an outgoing Administrator concluded that acid deposition was endangering public health in the U.S. and Canada, obligated future EPA Administrators to take the regulatory action under CAA §115 that would be triggered by such a finding. Because any EPA statement of future effect must be embodied in a legislative “rule” in order to bind a future Administrator, id. at 1446-47, and because the Administrator had not made the §115 findings in a notice-and-comment rulemaking, this Court found in Thomas that it was not a “rule” and thus had no legal consequences. Id. at 1447. Petitioner UARG sought judicial review of the December 2000 finding. That petition was dismissed by this Court on finality grounds. See supra p.14. In New Jersey, petitioner UARG relied on Thomas in defending EPA’s 2005 §112(n)(1)(A) finding, which was made after a notice-and-comment §307(d) rulemaking and which rejected the earlier December 2000 finding. This Court, however, held that, because EPA did not cite or rely on Thomas in its brief, the Court would not consider the Thomas argument in UARG’s brief in New Jersey. New Jersey, 517 F.3d at 581 n.3. Accordingly, because this Thomas-based argument could not be resolved in New Jersey, that argument is now suitable for review for the first time under §307(b). Because the December 2000 §112(n)(1)(A) finding could not, under Thomas, be given legal consequences for future EGU regulation, it could not 28 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 69 of 177 provide the basis for a §112(c) EGU listing decision. Without a lawful listing, EPA had no obligation, or authority, to adopt any standards for EGUs under §112(d). On this basis alone, EPA’s EGU MACT standards must be vacated. B. EPA’s Current Interpretations of §112(n)(1)(A) Are Unlawful. 1. Section 112(n)(1)(A) Authorizes Regulation Only of Those EGU HAPs for Which EPA Makes an “Appropriate and Necessary” Finding. In its December 2000 §112(n)(1)(A) notice, EPA announced that mercury emissions from coal-fired EGUs merited regulatory consideration under §112. 65 FR at 79827/3 (JA__). Then, in its 2005 rulemaking, EPA determined that mercury was the only HAP from coal-fired EGUs warranting consideration. 70 FR at 16002/1-2 (JA__). In 2012, EPA changed course and now interprets §112(n)(1)(A) to require regulation of all HAPs emitted by EGUs whether or not those emissions pose hazards to public health, provided that EPA makes a health finding for at least one EGU HAP. This change in interpretation is inconsistent with the statute and is unreasonable. Section 112(n)(1)(A) directs EPA (i) to study “hazards to public health reasonably anticipated to occur as a result of emissions by [EGUs]” of listed HAPs and then to report to Congress the results of that study, and (ii) based on those results, to devise “alternative control strategies for emissions which may warrant regulation under this section.” Id. (emphasis added). This language requires EPA 29 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 70 of 177 to identify specific EGU HAPs “which may warrant regulation” based on specific public health hazards they engender, and not to regulate “all HAPs” regardless of hazards to public health and regardless of whether they may warrant regulation. Furthermore, §112 directs EPA to regulate EGU HAPs under §112 only if it finds “such regulation” is “appropriate and necessary.” §112(n)(1)(A) (emphasis added). “Such regulation” cannot be “appropriate and necessary” for any EGU HAPs that do not pose “hazards to public health.” Rather, regulation is reserved by the plain terms of §112(n)(1)(A) to EGU HAPs that pose hazards to public health, and the regulation of which is “appropriate and necessary.” Indeed, regulating emissions that do not pose hazards is incompatible with the fundamental purpose of the CAA “to protect and enhance the quality of the Nation’s air resources so as to promote the public health and welfare and the productive capacity of the population.” §101(b)(1). Yet under EPA’s interpretation of the CAA, EPA’s 2000 “appropriate and necessary” finding for mercury compels severe regulatory compliance requirements for non-mercury HAPs—requirements that remain wholly inappropriate and unnecessary given the more recent information EPA now advances for those substances. See infra Argument I.C. The legislative history supports this commonsense reading of §112(n)(1)(A). As explained by the sponsor of this provision, EPA’s authority to regulate EGUs is premised on EPA’s ability to “clearly establish that emissions of any pollutant, or 30 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 71 of 177 aggregate of pollutants, from such units cause a significant risk of serious adverse effects.” 136 Cong. Rec. H12934 (daily ed. Oct. 26, 1990) (statement of Rep. Oxley), reprinted in 1 1990 Legis. Hist. at 1416-17 (“Oxley Statement”) (JA____). Though now discounting Representative Oxley’s statement, EPA previously relied on the very same statement to support its interpretation of §112(n)(1)(A). Compare 77 FR at 9322/1-2 (JA__) with 70 FR at 16000/2 (JA__). In the 2000 “appropriate and necessary” notice of finding, EPA concluded that mercury emissions were a “threat to public health.” 65 FR at 79827/2 (JA__); see also New Jersey, 517 F.3d at 578 (citing mercury as the basis for 2000 “appropriate and necessary” finding). In 2004, EPA confirmed that based on the 2000 record “it could not reasonably have reached…a conclusion” that other HAPs should be considered for regulation under §112, stating that the “record supports only a finding that emissions of Hg and Ni warrant regulation.” 69 FR at 4683/2 (JA__). At the time, some commenters claimed that this Court’s decision in National Lime Ass’n v. EPA, 233 F.3d 625, 633 (D.C. Cir. 2000), required EPA “to promulgate emission standards for all power plant HAP emitted in significant quantities.”35 EPA disagreed, stating that EGUs are regulated differently from 35 EPA, RTC Concerning Proposed Revision of 2000 Finding and Removal of EGUs from §112(c) List, at 14 (Mar. 15, 2005), EPA-HQ-OAR-2002-00566193 (JA__). 31 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 72 of 177 other source categories under §112, and that §112(n)(1)(A) limits regulation to those HAPs that are “appropriate” to regulate.36 After rulemaking, EPA thus interpreted §112(n)(1)(A) in a manner consistent with its plain language: to authorize regulation under the “appropriate and necessary” standard only of those HAPs that pose hazards to public health. Reversing its prior position, EPA now construes §112(n)(1)(A) to require EPA “to regulate all HAP from major sources of HAP emissions once a source category is added to the list of categories under CAA section 112(c),” citing National Lime, 233 F.3d at 633 (JA__). 77 FR at 9326/1. Under this view, EPA has no discretion to limit its regulations of EGUs to only those HAPs “which may warrant regulation” under §112(n)(1)(A). In changing its 2005 rulemaking interpretation, other than citing National Lime, EPA does nothing to explain. EPA does not engage the statutory language or purposes. Nor does EPA explain why it is rejecting its previous view of the CAA and of National Lime. As EPA explained in 2005, National Lime does not address §112(n)(1)(A). Rather, it involved the regulation of major sources generally under §112(c) and (d). For non-EGU sources, §112(c)(1) requires EPA to publish and maintain a list of “major sources” of HAP emissions. “Major sources” are defined in §112(a)(1) 36 Id. at 16 (JA__). 32 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 73 of 177 by the objective amount of their HAP emissions, not by EPA’s discretionary view of whether regulation of an EGU HAP emission that poses a health hazard is “appropriate and necessary.” Reliance on National Lime’s interpretation of different statutory provisions is therefore misplaced. Radzanower v. Touche Ross & Co., 426 U.S. 148, 153 (1976) (“Where there is no clear intention otherwise, a specific statute will not be controlled or nullified by a general one.”) (emphasis added); Norwest Bank Minn. Nat’l Ass’n. v. FDIC, 312 F.3d 447, 451 (D.C. Cir. 2002) (“When both specific and general provisions cover the same subject, the specific provision will control.”). EPA’s reliance on National Cable & Telecommunications Ass’n v. Brand X Internet Services, 545 U.S. 967 (2005), is also misplaced. See 77 FR at 9323/1 (JA__). It is insufficient for EPA to assert, without explanation, that its new interpretation is “reasonable” when that interpretation differs from its interpretation in 2000 and 2005. See id. “[A]n agency changing its course…is obligated to supply a reasoned analysis for the change….” See Motor Vehicle Mfrs. Ass’n, 463 U.S. at 42 (emphasis added). Here, EPA’s bald assertion that its changed interpretation is “reasonable” and therefore accorded “deference,” without analyzing the different statutory provisions Congress adopted for EGUs and other sources as EPA did in its 2005 rulemaking interpretation, must fail and the rule must be vacated. See, e.g., Mass. Trs. v. United States, 377 U.S. 235, 248 (1964) 33 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 74 of 177 (regulation based on an incorrect view of applicable law cannot stand as promulgated); PDK Labs., Inc. v. DEA, 362 F.3d 786, 797-98 (D.C. Cir. 2004); see also Prill, 755 F.2d at 947-48 (agency action premised on a mistaken conclusion that the agency has no discretion is inherently arbitrary and must be reconsidered based on a proper understanding of the agency’s discretion); Transitional Hosps. Corp. v. Shalala, 222 F.3d 1019, 1029 (D.C. Cir. 2000) (same). 2. EPA’s Application of the §112(c)(9) Delisting Criteria in Making the §112(n)(1)(A) “Appropriate and Necessary” Finding Is Unlawful. In 2005, EPA declined to interpret §112(n)(1)(A) to incorporate the “ample margin of safety” standard found in §112(f). 70 FR at 16001/3 (JA__). Rather, EPA interpreted the statute more broadly, finding that §112(n)(1)(A) “called on EPA to consider the ‘hazards to public health reasonably anticipated to occur’ from utility HAP emissions’...in determining whether it is both appropriate and necessary to regulate [EGUs] under section 112.” Id. Now, on the grounds that §112(n)(1)(A) “neither defines the phrase ‘hazards to public health’” nor “sets forth parameters for EPA to use in determining whether HAP emissions from EGUs pose a hazard to public health,” 76 FR at 24992/3 (JA__), EPA concludes for the first time that the §112(c)(9) criteria for delisting source categories is a sufficient basis for determining that it is “appropriate” to regulate EGUs under §112(n)(1)(A). 76 FR at 24992/2 (“[W]e conclude today that 34 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 75 of 177 it is appropriate to regulate non-Hg HAP because emissions of these HAP from some EGUs pose a cancer risk greater than one in one million to the most exposed individual.”) (JA__). At the outset, the §112(c)(9) evidentiary standard for delisting—“may result”—is different from the evidentiary test governing a §112(n)(l)(A) finding— “reasonably anticipated to occur.” Furthermore, the delisting provision applies that different evidentiary standard to both “health” and “environmental” effects whereas §112(n)(l)(A) requires EPA to focus exclusively on health hazards in selecting EGU HAP candidates for regulation. See infra p.44. These differences in language alone preclude an interpretation of §112(n)(l)(A) as incorporating the regulatory tests in §112(c)(9). More fundamentally, EPA’s interpretation of the phrase “hazards to public health” is inconsistent with the language and structure of §112. As discussed, Congress wrote §112(n)(1)(A) to treat EGUs differently from all other “major sources,” requiring an evaluation of whether it is “appropriate and necessary after considering the results of the study” on EGU HAP emissions to list those sources for §112 regulation. By applying the delisting provisions of §112(c)(9) in making the initial, pre-listing determination whether it is “appropriate and necessary” to regulate EGUs, EPA has unlawfully imposed requirements on itself that Congress chose not to impose at the listing stage. Essentially, EPA would treat EGUs the 35 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 76 of 177 same as all other major source categories—as a category that must be listed unless the delisting criteria are met. Because this approach is inconsistent with the statute, the rule must be set aside. 3. A §112(n)(1)(A) Finding Does Not Compel Regulation Under §112(d). Even if EPA had properly determined that it is “appropriate and necessary” to regulate EGU HAP emissions, EPA misinterpreted the statute by concluding that those emissions must be regulated through MACT standards under §112(d), and cannot be regulated under §112(n)(1)(A) to the degree “appropriate and necessary.” Had Congress intended that EPA regulate EGU HAP emissions only through §112(d), Congress would have directed EPA to regulate EGU emissions “under §112(d)” once an “appropriate and necessary” finding was made. Congress did not do so, stating instead that “[t]he Administrator shall regulate [EGUs]…under this section” upon such a finding. added). §112(n)(1)(A) (emphasis Indeed, Congress specifically rejected the Senate bill that expressly prescribed a “list-under-(c)-and-regulate-under-(d)” approach for EGUs similar to the approach for other source categories. See infra p.6. Under §112(n)(1)(A), Congress directed EPA to establish “such regulation” for EGUs that is “appropriate and necessary after considering the results of the study required by this subparagraph.” §112(n)(1)(A) (emphasis added). Regulation of EGU HAPs that do not pose hazards to public health, or regulation at 36 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 77 of 177 a level that is greater than needed to eliminate the hazard, is not “regulation [that] is appropriate and necessary.” Id. Thus, §112(n)(1)(A) itself provides EPA authority to regulate EGU HAP emissions, as EPA concluded in 2004 when it proposed §112(n)(1)(A) as a regulatory alternative. 69 FR at 4661/2 (JA__). In this regard, MACT standards control emissions without regard to what is “appropriate” or “viable” regulation. See, e.g., Sierra Club v. EPA, 479 F.3d 875, 883 (D.C. Cir. 2007) (§112(d)(3) requires EPA to set standards based on the best performing sources even if EPA believes such standards are “not ‘appropriate’ or ‘viable’”). In any specific case, a MACT standard might provide more or less control than is needed to address the hazards identified under §112(n)(1)(A), cf. EME Homer City, 2012 WL 3570721, at *11-12 (“[EPA] must avoid using [§110(a)(2)(D)]…in a manner that would result in unnecessary over-control….and may not exceed a statute’s authorization or violate a statute’s limits.”), or may result in control strategies different from those identified by EPA for emissions that may warrant regulation. In either case, applying the MACT standard-setting criteria would not result in “such regulation [as] is appropriate and necessary.” Cf. Whitman v. Am. Trucking Ass’ns, 531 U.S. 457, 473 (2001) (“requisite” means “sufficient, but not more than necessary…to protect public health”). Further, EPA’s current interpretation makes identification of “alternative control strategies for emissions which may warrant regulation” a meaningless 37 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 78 of 177 exercise. If Congress had intended that EPA regulate EGU HAP emissions only by establishing standards based on the MACT floor and beyond-the-floor provisions in §112(d), then there is no need to identify such alternative control strategies. By rendering meaningless the §112(n)(1)(A) requirement that EPA identify alternative control strategies for emissions that may warrant regulation, EPA’s interpretation is unlawful and must be rejected. See Mac’s Shell Serv., Inc. v. Shell Oil Prods. Co., 130 S. Ct. 1251, 1261 (2010) (statutes should not be interpreted to render a provision meaningless). Finally, by making the rulemaking requirements of §307(d) applicable to the “promulgation…of any…regulation under section 7412…(n),” §307(d)(1)(C) (emphasis added), Congress confirmed that §112(n)(1)(A) confers authority to establish “such regulation [as] is appropriate and necessary” to address those “emissions which may warrant regulation.” In sum, EPA misconstrued the statute as compelling regulation under §112(d) and precluding any regulation of EGUs under §112(n)(1)(A). See 77 FR at 9330/2 (JA__). EPA’s §112(d) MACT standards therefore must be vacated. See, e.g., Transitional Hosps. Corp., 222 F.3d at 1029; Prill, 755 F.2d at 948; SeaLand Serv., Inc. v. DOT, 137 F.3d 640, 646 (D.C. Cir. 1998). 38 USCA Case #12-1100 4. Document #1401252 Filed: 10/23/2012 Page 79 of 177 EPA Failed To Consider the Costs of Regulation in Its Appropriate and Necessary Finding. In 2005, EPA construed §112(n)(1)(A) to allow consideration of costs in determining whether and to what extent regulation of EGU HAP emissions is “appropriate” following a finding that public health hazards warrant regulation. 70 FR at 16000/3-01/1 (JA__-__). (“Even if the remaining utility HAP emissions cause hazards to public health, it still may not be appropriate to regulate [EGUs] under section 112 because there may be other relevant factors [such as cost]…that would lead the Agency to conclude that it is not…‘appropriate’ to regulate [EGUs] under section 112.”). In this rulemaking, EPA has abruptly changed course and “reject[ed]” its “2005 interpretation that authorizes the Agency to consider other factors (e.g., cost)” in determining whether regulation is “appropriate.” 76 FR at 24989/3 (JA__). EPA’s new interpretation unreasonably constrains the language of §112(n)(1)(A). “Appropriate” is not defined in the CAA. It is defined by Webster’s Dictionary to mean “especially suitable or compatible.” Webster’s Online Dictionary, Merriam- http://www.merriam- webster.com/dictionary/appropriate (last accessed Oct. 23, 2012). See also New Oxford American Dictionary (2d ed. 2005) (“Appropriate” means “suitable or proper in the circumstances.”); Schindler Elevator Corp. v. United States ex rel. 39 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 80 of 177 Kirk, 131 S.Ct. 1885, 1891 (2011) (relying on dictionary definition of term not defined in statute). Based on the plain meaning of “appropriate,” it is “suitable” and “proper” to take into account costs to the nation’s electricity generators when deciding whether to regulate EGUs. The impact of those costs will ripple throughout the Nation’s economy, affecting consumers, small businesses, industry, and all levels of government. Excluding consideration of costs would be improper and unsuitable, given the fundamental role that electricity generation plays in all economic activity. TVA v. EPA, 278 F.3d 1184, 1208 (11th Cir. 2002). EPA’s new interpretation also ignores critical differences between regulating EGUs under §112(n)(1)(A) and regulating other sources under §112(c). Regulation of major sources other than EGUs is mandatory pursuant to the twostep listing and then standard-setting process Congress established in §112(c) and (d). Under §112(c), only the quantity of emissions plays a role in determining whether a source category is listed.37 In contrast, Congress required in §112(n)(1)(A) that EGUs be regulated only if EPA determines it is both “appropriate” and “necessary” after considering the results of the Utility Study. In short, the fact that §112(c) establishes an automatic listing requirement that does not allow for consideration of costs for sources other than EGUs, 77 FR at 9327/1 37 See §112(a)(1) (defining “major source”). 40 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 81 of 177 (JA__), does not inform whether cost considerations must factor into EPA’s “appropriate” finding under §112(n)(1)(A) for EGUs. It is “the settled law of this circuit” that “[i]t is only where there is ‘clear congressional intent to preclude consideration of cost’ that we find agencies barred from considering costs.” Michigan v. EPA, 213 F.3d 663, 678 (D.C. Cir. 2000) (quoting NRDC v. EPA, 824 F.2d 1146, 1163 (D.C. Cir. 1987)). Here, there is no “clear congressional intent” that precludes EPA from taking costs into account in determining appropriateness. To the contrary, EPA is required to consider the extraordinary costs that would be imposed by the MATS rule given the plain meaning of “appropriate,” Congress’s use of that term in §112(n)(1)(A), and §112’s structure. EPA’s interpretation of “appropriate” is also unlawful because it eliminates the discretion that Congress intended EPA to exercise after completing the Utility Study. EPA claims it “must find that it is appropriate to regulate EGUs if it determines that any single HAP emitted by utilities poses a hazard to public health or the environment.” 76 FR at 24988/1 (emphasis added) (JA__). But §112(n)(1)(A) provides that EPA—through the Utility Study—would first identify “a health hazard” from HAPs emitted from EGUs, and then determine whether regulation of that health hazard is “appropriate and necessary.” 41 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 82 of 177 If Congress wanted to require EPA to regulate without any further consideration if the Study identified “a hazard,” it would have said so. Instead, Congress gave EPA discretion to decide whether to regulate if the Utility Study identified hazards to public health. And the discretion Congress wanted EPA to exercise includes an evaluation of the costs and benefits of addressing whatever hazards are identified in the Utility Study.38 EPA unlawfully eliminated the exercise of that discretion by incorrectly interpreting “appropriate” to preclude consideration of costs. When the costs and potential benefits of the MATS rule are considered, it is unmistakable that regulation of EGUs is not appropriate. According to EPA, the annual cost to comply with the rule is $9.6 billion. 77 FR at 9306, Table 2 (JA__). The adverse impact of EPA’s rule on the reliability of the electrical grid because of early plant retirements will impose additional costs.39 38 By contrast, the rule’s For example, §112(n)(1)(A) directs EPA to “develop and describe…alternative control strategies” for those “emissions which may warrant regulation under this section.” §112(n)(1)(A). An evaluation of “alternative” controls includes an assessment of both the amount of HAPs controlled by different control techniques and their costs. 39 Texas has its own power grid. Texas electricity producers rely heavily on the state’s own natural resources, including coal. EPA’s promulgated emission limits will effectively end the construction of new coal-fired facilities (and may cause the closure of existing facilities). Texas cannot offset these losses by using power from other sources because it is not sufficiently connected to any other power grid. EPA failed to adequately consider and account for reliability issues unique to Texas. Texas Commission on Environmental Quality, Comments on 42 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 83 of 177 benefits of reducing HAPs are de minimis: only $4 to $6 million in 2016 based on EPA’s analysis of health effects due to recreational freshwater fish consumption. Id. Put another way, it would cost at least $1,500 for $1 of benefit in HAP emission reductions. Although EPA estimated the rule’s “Total Monetized Benefits” to be $37 to $90 billion, nearly all ($36 to $89 billion) are attributed to a non-HAP substance regulated under other CAA provisions—“PM2.5-related Co-benefits.”40 EPA insists, however, it did not base the “appropriate and necessary finding on hazards to public health attributable to PM emissions.” Id. at 9320/1 (JA__). Consequently, the only health benefit from HAP reductions attributable to the rule are the $4 to $6 million in benefits associated with eating fish. Perhaps EPA could demonstrate it is appropriate to spend $9.6 billion every year to achieve an annual health benefit of $4 to $6 million from reducing HAP emissions, or that spending a significant part of that $9.6 billion annually is justified to reduce acid gas emissions that pose no health or quantifiable environmental impact.41 EPA, however, never performed any such analysis and did not base its “appropriate” finding on those grounds, given its incorrect Proposed Rule at 1-2, 26-28 (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-18034 (JA__-__, __-__). 40 Additional “co-benefits” are “Climate-related Co-Benefits” of $36 million in 2016. Id. 41 As noted above, EPA cites a single study for its acid gas finding that does not even examine the EGU acid gas emissions EPA has determined to regulate. 43 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 84 of 177 interpretation that §112(n)(1)(A) precludes such considerations. EPA’s failure to take costs into account, as Congress intended, requires vacatur of the MATS rule. 5. EPA Violated §112(n)(1)(A) by Making Environmental Effects the Trigger for an “Appropriate and Necessary” Finding. CAA §112(n)(l)(A) calls for a study that focuses exclusively on identifying EGU HAP emissions that pose “hazards to public health” and directs EPA to regulate those emissions only if “appropriate and necessary…considering the results of the study.” In 2005, EPA read §112(n)(1)(A) in accordance with its plain text, as excluding emissions that only had environmental effects from the emissions that the Utility Study could target for “appropriate and necessary” evaluation. 70 FR at 15998/1-2 (JA__).42 EPA explained that: [W]e believe that environmental factors unrelated to public health, although they can be considered in the appropriate inquiry, may not independently or, in conjunction with one another, justify regulation of Utility Units under section 112 when EPA has concluded that hazards to public health are not reasonably anticipated to result from utility HAP emissions. Id. at 16002/3 (JA__). 42 As EPA itself recounted in its petition for certiorari in New Jersey, consideration of environmental impacts is “inconsistent with the text of Section 7412(n)(1)(A), under which ‘the condition precedent for regulation…is public health hazards, not environmental effects.’” EPA Pet. for Cert. at 7, EPA v. New Jersey, No. 08-512 (U.S. Oct. 17, 2008) (ellipsis in original, citation omitted) (JA__). 44 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 85 of 177 In 2012, EPA abandoned the CAA’s plain meaning and its 2005 interpretation, saying that §112(n)(1)(A) “require[s] the Agency to find regulation of EGUs…appropriate if we determine that HAP emissions from EGUs pose a hazard to public health or the environment at the time the finding is made.” See 76 FR at 24988/1 (emphasis added) (JA__); 77 FR at 9325/1 (JA__)). EPA argues that if Congress meant to “prohibit EPA from considering adverse environmental effects” as a primary criterion for selecting emissions that would be evaluated in an “appropriate” finding under §112(n)(1)(A), it was incumbent on Congress to have “stated so expressly.” 76 FR at 24988/2 (JA__) (referenced at 77 FR at 9325/1 (JA__)). Congress, however, knew how to direct EPA to consider environmental impacts in making regulatory choices and did not do so in §112(n)(1)(A). Numerous other provisions of §112, including elsewhere in §112(n), expressly require consideration of both health and environmental effects.43 Thus, the fact that “environmental effects” are not mentioned in §112(n)(1)(A) does not give EPA license to consider such effects as a key factor that triggers an “appropriate and necessary” evaluation under §112(n)(1)(A). Instead, omission of “environmental effects” from §112(n)(1)(A) is a clear signal that those effects are not what brings an EGU HAP into this program. 43 See §112(n)(5) & (6); §112(b)(2); §112(e)(2)(A). 45 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 86 of 177 The Supreme Court has recognized that “where Congress includes particular language in one section of a statute but omits it in another section of the same Act, it is generally presumed that Congress acts intentionally…in the disparate inclusion or exclusion.” Russello v. United States, 464 U.S. 16, 23 (1983). Similarly, in Ethyl Corporation v. EPA, 51 F.3d 1053, 1058 (D.C. Cir. 1995), this Court rejected EPA’s assertion that it could make public health impacts the focus of its regulatory determination even though the statute lacked any mention of such impacts: “Section 211(f)(4) instructs the Administrator to consider a new fuel additive’s effects only on emission standards. The language of the provision…is specific and definite; it does not permit the Administrator to consider other factors ‘in the public interest.’” Id. at 1058. The legislative history confirms that under §112(n)(1)(A), EPA “may regulate [EGUs] only if the studies described in section 112(n) clearly establish that emissions of any pollutant…from such units cause a significant risk…on the public health.”44 Because EPA made environmental effects of HAPs a key factor, and in the case of acid gas HAPs the only factor, in its appropriate and necessary determination, the MATS rule is contrary to law and must be set aside. 44 Oxley Statement at 1416 (emphases added) (JA__). 46 USCA Case #12-1100 6. Document #1401252 Filed: 10/23/2012 Page 87 of 177 EPA Improperly Considered the Impacts of Non-EGU HAP Emissions as the Trigger for an “Appropriate and Necessary” Finding. EPA acknowledges that the “appropriate and necessary” finding is based on the EGU emissions addressed in the “Utility Study,” and that the “scope of the Utility Study was limited to HAP emissions from EGUs.” 77 FR at 9322/2 (JA__); 76 FR at 24987/3 (JA__). Contrary to its 2005 interpretation, EPA now interprets §112(n)(1)(A) as authorizing regulation without a showing that EGU emissions “alone would cause the harm.”45 EPA’s interpretation again conflicts with the language of §112(n)(1)(A), which makes EGU emissions that have been identified in the Utility Study the trigger for an “appropriate and necessary” determination. Furthermore, under §112(n)(l)(A) only hazards “reasonably anticipated to occur as a result of” EGU HAPs emissions may be evaluated by EPA, not EGU emissions that may contribute to a hazard that “occur[s] as a result of” HAPs emitted by other sources. Here again, EPA has departed from numerous CAA provisions that distinguish between emissions that cause harm and emissions that 45 77 FR at 9325/3 (JA__). EPA’s consideration of emissions from other sources plays a key role in its “appropriate and necessary” finding for mercury and the acid gas HAPs. See EPA, Hg Risk Technical Support Document (“TSD”), §2.3 Table 2-5 (Dec. 2011), EPA-HQ-OAR-2009-0234-19913 (EPA’s mercury study based on methylmercury levels in fish where EGUs’ contribution to fish tissue levels was on average 3.4%) (JA__); 77 FR at 9362/1 (“Given the extent and importance of the sensitive ecosystems evaluated in the review of nitrogen and sulfur deposition any substance [acid gas HAP] that contributes to further acidification must be considered to be affecting the public welfare.”) (JA__). 47 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 88 of 177 contribute to harm. Compare §111(b)(1)(A) (addressing emissions that “cause[], or contribute[] significantly to, air pollution”) with §112(n)(l)(A) (addressing hazards that “occur as a result” of EGU HAPs). The legislative history confirms that EPA’s authority is limited initially to consideration of hazards associated with HAP emissions from EGUs. As the sponsor of §112(n) explained, EPA “may regulate fossil fuel fired electric utility steam generating units” only if emissions of any pollutant “from such units” cause a significant risk of serious adverse effects to the public health.46 Thus, the regulation of EGUs is authorized only if EPA were to determine that HAP emissions from EGUs (not EGU HAP emissions plus HAP emissions from other sources) cause a significant risk of serious adverse effects to the public health. Because EPA’s “appropriate and necessary” finding is based on public health hazards associated with non-EGU emissions, this rule must be set aside. C. EPA’s “Appropriate Unlawful. and Necessary” Determinations Are In addition to defending its 2000 “appropriate and necessary” finding on its own terms, EPA advances new technical information in support of this finding. But neither the 2000 information nor the new information provide a rational basis for that finding. 46 Oxley Statement at 1416 (emphasis added) (JA__). 48 USCA Case #12-1100 1. Document #1401252 Filed: 10/23/2012 Page 89 of 177 Mercury EPA’s 2000 finding addressed nationwide exposures to mercury from all sources and concluded that “mercury is both a public health concern and a concern in the environment.”47 EPA then made the qualitative observation that “there is a plausible link between methylmercury concentrations in fish and mercury emissions from coal-fired [EGUs].”48 EPA could not, however, quantify “the degree to which that linkage occurs.”49 By failing to quantify the contribution of EGUs to methylmercury in fish, EPA had no factual basis for concluding that health hazards were “reasonably anticipated to occur as a result of [EGU] emissions.” 70 FR at 16006/3 (JA__). In 2005, EPA conducted extensive modeling to quantify the public health significance of EGU mercury emissions. The modeling showed that total EGU mercury emissions would be reduced from 48.57 tpy in 2001 to 34.42 tpy in 2020 due solely to the implementation of other CAA requirements, including CAIR.50 The modeling also demonstrated that further reductions beyond this 34 tpy level would have little or no impact on methylmercury levels in fish51 and, hence, would not significantly reduce human exposure to methylmercury. As a result, EPA 47 65 FR at 79830/1 (JA__). Id. 49 Id. 50 70 FR at 16018, Table VI-2 (JA__). 51 Id. at 16020, Table VI-6 (JA__). 48 49 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 90 of 177 concluded that “the [national] level of Hg emissions [34.42 tpy] projected to remain ‘after imposition of’ section 110(a)(2)(D) does not cause hazards to public health,”52 and that regulation of EGU mercury emissions under §112 was not “appropriate.”53 The 2012 MATS rulemaking did not abandon EPA’s 2005 mercury modeling. In fact, the mercury emissions data from the 2010 ICR show that EPA’s 2005 modeling had significantly overstated the amount of mercury EGUs emit without any §112 regulation. Based on more recent data, EPA estimated that EGU’s 2010 mercury emissions were 29 tpy compared to the 34.42 tpy it projected in 2005 as presenting no hazard to public health. EPA’s failure to address the 2005 study and explain why that study no longer supports the conclusion that EPA reached in 2005, see, e.g. Motor Vehicle Mfrs. Ass’n, 463 U.S. at 42, renders EPA’s 2012 determinations arbitrary and capricious. Without addressing its 2005 analysis, EPA conducted an entirely new analysis to assess mercury risk in the context of IQ benefits. The Science Advisory Board (“SAB”) panel convened by EPA to review that analysis reported that SAB reviewers “could not evaluate the [new] risk assessment based …[on] information 52 53 Id. at 16004/2 (JA__). Id. 50 USCA Case #12-1100 Document #1401252 provided in the [TSD]. Filed: 10/23/2012 Page 91 of 177 Important elements of the methods and findings are missing or poorly explained.”54 The Mercury TSD employs a series of assumptions that vastly overstate mercury exposure.55 Even with these overestimates, EPA could only calculate an aggregate public health benefit from the MATS rule of a total of 510 IQ points to the most sensitive individuals (prenatally-exposed children).56 This hypothetical increment of two one-thousandths of an IQ point for each individual in that population, RIA at 4-56 (JA__), is too small to have any scientifically discernible meaning or public health impact. These results confirm EPA’s 2005 rulemaking conclusion that mercury emissions do not present a public health hazard, and require that the MATS rule be set aside. 2. Other HAP Metals EPA used its prior dispersion modeling and select emissions data from the 2010 ICR to identify 16 facilities that it believed were likely to present high offsite risks of cancer from emissions of non-mercury HAP metals. EPA, Non-Hg SAB letter to EPA Adm’r Jackson at 1 (Sept. 29, 2011), EPA-SAB-11-017 (JA__). The SAB final report was submitted almost two months after the public comment period closed. EPA refused to grant the SAB panel’s request that it be provided an opportunity to review the final TSD. 55 UARG Comments at 6, 58-72 (JA__, __-__); EPRI MATS Rule Comments at 3-1, 3-10 to -11, App. G at G1-12 (JA__, __-__, __-__). The Hg exposure levels EPA calculated in the Mercury TSD are more than 2 times higher than those in the Utility Study, despite Hg emissions having decreased almost 45%; Southern Comments, Attachments B & C (JA__, __). 56 See RIA at 4-56 (JA__). 54 51 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 92 of 177 Case Study Memo at 1-2 (Mar. 16, 2011), EPA-HQ-OAR-2009-0234-2939 (JA__). EPA’s goal was to find a single EGU presenting risks greater than one-in-one million for the most exposed individuals, which EPA then used to support an “appropriate and necessary” finding.57 EPA’s abbreviated modeling effort was infected with errors. Contrary to over a decade of EGU emissions data and modeling, hexavalent chromium emissions drove the risk estimate for the five coal-fired units with risks that slightly exceeded the one-in-one million level. See UARG Comments at 7576 (JA__-__). A simple review of the sampling results for these facilities showed that the removal efficiencies for chromium and nickel for these units were far different than for other trace metals. These results suggested sample contamination. EPA, MATS ICR Data, Coal HAP Metals spreadsheet at “Coal Metals Data” tab (Dec. 16, 2011) (JA__). Despite comments raising the sample contamination issue, EPA refused to change the chromium emission inputs. 77 FR at 9357/1 (JA__).58 Had EPA used Under EPA’s theory, because a single, isolated plant posing off-site risks greater than one-in-one million would violate the §112(c)(9) delisting criteria, it would also require an “appropriate and necessary” finding under EPA’s new interpretation of §112(n)(1)(A). See 76 FR at 24999/2 (“[W]e conclude today that it is appropriate to regulate non-Hg HAP because emissions of these HAP from some EGUs pose a cancer risk greater than one in one million to the most exposed individual.”). 58 Subsequent resampling at each of those facilities shows that the high chromium levels that EPA calculated resulted from sample contamination caused 57 52 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 93 of 177 correct chromium emissions information, no selected EGU would have presented a risk greater than one-in-one million from non-mercury metal HAPs. As a result, even applying §112(c)(9) as the listing criterion, EPA’s “appropriate and necessary” finding for other HAP metals lacks factual support. 3. Acid Gas HAPs EPA’s conclusion that it is appropriate and necessary to regulate acid gas HAPs is not premised on public health risk. 76 FR at 25016/3 (“[O]ur case studies did not identify significant chronic non-cancer risks from acid gas emissions.”) (JA__). Indeed, EPA’s modeling has consistently shown that exposures from EGU acid gas HAP emissions are an order of magnitude or more below EPA’s health thresholds defining a safe level of exposure.59 It is not “appropriate and necessary” to regulate EGU emissions under §112 that pose no health hazard. In support of its §112(n)(1)(A) finding for acid gases, therefore, EPA cites environmental effects—unquantified acidification effects60—and co-benefits from by stainless steel fittings used in the sampling trains. UARG, Petition for Reconsideration of MATS Rule at 6-7 (Apr. 16, 2012), EPA-HQ-OAR-2009-023420179 (JA__-__). When stainless steel fittings were removed, chromium emissions for those units were one to two orders of magnitude below the levels EPA used in its risk modeling. 59 See UARG Comments at 116 (JA__); Utility Study at 6-1 (JA__); EPA, Supplement to Non-Hg Case Study at 12 & 13, Table 9 (Nov. 2011), EPA-HQOAR-2009-0234-19912 (JA__-__). 60 See 77 FR at 9362/1 (JA__). 53 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 94 of 177 reducing the criteria pollutant PM2.5.61 Even if §112(n)(1)(A) authorized EPA to regulate EGUs under §112 based solely on environmental impacts, EPA has no rational basis for making an “appropriate and necessary” determination for acid gases. EPA’s “evidence” on the environmental impacts of EGU acid gas HAP emissions consists of EPA’s general claim that “[i]n areas where the deposition of acids derived from emissions of sulfur and NOx are causing aquatic and/or terrestrial acidification, with accompanying ecological impacts, the deposition of hydrochloric acid could exacerbate these impacts.” 76 FR at 25050/3 (emphasis added) (JA__). EPA then references one study on HCl deposition in the United Kingdom, which EPA cites for the proposition that: (a) HCl is highly mobile in the environment, (b) HCl can transport longer distances than previously thought, and (c) HCl can be a larger driver of acidification than previously thought. 77 FR at 9362 (JA__). EPA does not even attempt to quantify the impact, if any, of EGU emissions of HCl in the United States and, as a result, cannot point to even a single instance in which EGU HCl emissions have affected acid deposition anywhere or otherwise created an environmental impact. This paucity of analysis is especially striking given that a significant portion of the $9.6 billion in annual costs that EPA See 77 FR at 9306, Table 2 (vast majority of benefits attributable to PM2.5 reductions), 9446/2 (“substantial health benefits…from reductions in PM2.5”) (JA__, __). 61 54 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 95 of 177 would impose on EGUs stems from EPA’s decision to regulate acid gas HAPs. See supra note 33. Because EPA’s appropriate and necessary finding for acid gases lacks record support, even under EPA’s unlawful environmental effects standard, the rule must be vacated. II. ASSUMING ARGUENDO THAT THE REQUIREMENTS OF §112(d) GOVERN THE VALIDITY OF EPA’S EGU MACT STANDARDS, THOSE STANDARDS ARE UNLAWFUL UNDER §§112(c) AND (d). As discussed in the foregoing section, the Court should vacate the MACT standards because EPA unlawfully construed and implemented §112(n)(1)(A). If the Court nonetheless finds that EPA’s §112(n) interpretations were permissible and its §112(n) findings had record support, the standards should nonetheless be set aside for the reasons discussed below. A. EPA’s EGU MACT Standards Failed To Distinguish Between Major Sources and Area Sources. CAA §112(d) calls for standards for two statutorily distinct and defined types of sources: “major sources” and “area sources” (i.e., sources that do not emit HAPs above the major source thresholds). Where §112(d) applies, EPA is required to establish MACT standards for all “major sources” in a listed category and (EPA believes) these standards must cover all HAPs emitted by those major sources. 55 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 96 of 177 To list and regulate “area sources,” “the Administrator [must] find[ ] [that a category or subcategory of area sources] presents a threat of adverse effects… warranting regulation….” §112(c)(3). Without an “area source” listing based on that finding, EPA has no authority to establish any standards under §112(d) for “area sources.”62 With such a finding and listing, EPA must determine which HAPs emitted by “area sources” to regulate and under what regulatory standard (i.e., generally available control technology” (“GACT”) or MACT).63 In promulgating the EGU MATS standards, EPA ignored each of these “area source” statutory prerequisites to regulation. EPA failed to identify a category or subcategory of EGU “area sources.”64 EPA made no finding that EGU “area source” HAP emissions create hazards “warranting regulation.” (EPA’s §112(n)(1)(A) findings were based on an evaluation of HAP emissions from all EGUs, instead of emissions from only those EGUs that are “area sources.”) EPA refused to explain adequately why it rejected adoption of GACT rather than MACT in establishing standards for EGU “area sources.” Finally, EPA concluded that National Lime required regulation of all HAPs emitted by EGUs, including all 62 When EPA listed coal- and oil-fired EGUs under §112(c) in 2002, it only listed major sources. It did not include a separate listing of EGU area sources. See 67 FR at 6521 (JA__). 63 See Newmont Nevada Energy Investment, LLC, Comments on Proposed MATS Rule at 2-8 (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-17871 (JA__-__). 64 EPRI estimated that approximately 12% of all coal-fired facilities are area sources. EPRI MATS Rule Comments at 2-31 to 2-33 (JA__-__). 56 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 97 of 177 HAPs emitted by EGU “area sources.” National Lime, however, only addressed an “all HAPs” standard-setting obligation with respect to “major sources.” See e.g., 76 FR 15554, 15567/1-3 (Mar. 21, 2011) (JA__). While each of these departures from the statute would require vacatur of the EGU MACT standards as applied to EGU “area sources,” the consequences of EPA’s failure to comply with Congress’ “area source” directives does not end with EGU “area sources.” EPA must establish MACT standards for “major sources” based on the performance, and characteristics, of a population of sources that consists exclusively of “major sources.” §112(d)(1). Here, EPA established MACT based on a population of EGUs that included both “major sources” and “area sources.” As a result, the MACT standards, as applied to major sources, are not based on the performance data required by statute and, therefore, must be vacated. Finally, EPA’s assertion that, by specifically defining EGUs in §112(a)(8), Congress intended that EGU MACT standards be established without regard to the distinction between “major” and “area” sources is, at best, an ipse dixit without any foundation in logic. See 77 FR at 9403/2 (JA__). The definition of EGU gives meaning to language found only in §112(n)(1)(A); there is no reference to EGUs in §112(c) and (d), except to exclude EGUs from coverage of §112(c)(6). As a result, there is no textual support for concluding that the requirements for listing “area 57 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 98 of 177 sources” under §112(c)(3) or for MACT standard-setting under §112(d) are different for EGUs (unless, as discussed in above, §112(n)(1)(A) provides the only basis for EGU regulation). As this Court noted, “where Congress wished to exempt EGUs from specific requirements of section 112, it said so explicitly.” New Jersey, 517 F.3d at 582. B. The Mercury Standard for Existing Sources Is Arbitrary and Capricious. CAA §112(d)(3)(A) requires EPA to set MACT limits for existing sources at least as stringent as the “average emission limitation achieved by the best performing 12 percent of the existing sources (for which the Administrator has emissions information).” This minimum level of stringency is commonly called the “MACT floor.” In 2009, EPA concluded that it needed additional EGU HAP emissions data to establish MACT floors. In designing an ICR, EPA had two options in choosing units to conduct stack sampling: (1) it could choose units on a purely random basis, or (2) it could select the presumed 12% of best performing units based on plant configurations and installed pollution control equipment that would result in the lowest emissions of a given HAP. The choice of the first option would require that MACT floors be calculated using a MACT pool comprised of the best performing 12% of units for which EPA had data. The choice of the second option would require MACT floors to be calculated using a larger MACT pool of the best 58 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 99 of 177 performing 12% of units in the entire category because the ICR sampling was designed to select the best 12% of the units in the entire industry. EPA chose the second option when it designed its EGU MACT ICR. As EPA explained to the Office of Management and Budget (“OMB”), EPA chose the 170-175 “best performing” units (out of 1091 units) for each HAP: For the Hg and other non-mercury metallic HAP group, EPA believes that units with the newest PM controls installed represent those units meeting the lowest PM emission limits, and, thus, are believed to be among the top performers with respect to Hg and other non-mercury metallic HAP emissions. Therefore, EPA has selected 175 units with the newest PM controls installed; of these 175, the newest 170 operating units will be required to conduct Hg and other non-mercury metallic HAP testing. ICR RTC at 27 (emphasis added) (JA__).65 Because the ICR was designed to test only the best performing units in the source category, EPA calculated the MACT floors for non-mercury metal and acid gas HAPs using a MACT pool of 131 units.66 By contrast, for existing coal-fired EGUs burning high-BTU coals, EPA calculated the MACT floor for mercury emissions using only data from the top 12% of the units for which it had data—40 units, or less than 4% of the industry—even though the ICR required testing by the There are 1091 coal-fired EGUs, and the top 175 units comprise about 16% of the industry. EPA selected slightly more than the 12% criterion due to uncertainties in precisely identifying the top 12% and concern that not all of the selected units would be available for testing. 66 Twelve percent of 1091 coal-fired EGUs is 131. 76 FR at 25023/1 (JA__); 77 FR at 9386/3 (JA__). 65 59 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 100 of 177 top mercury performers. EPA explained its decision to use a smaller pool of data as follows: For Hg from coal-fired units, we used the top 12 percent of the data obtained because, even though we required Hg testing for the units testing for the non-Hg metallic HAP, we did not believe those units represented the top performing 12 percent of sources for Hg in the category at the time we issued the ICR and we made no assertions to that effect. 76 FR at 25023/1 (emphasis added) (JA__). This claim is flatly contradicted by EPA’s own assertions to OMB when it sought approval of its ICR. It also is plainly contradicted by the facts. For example, the 170 units tested included 73% of all EGUs equipped with activated carbon injection (“ACI”)—the most advanced mercury removal technology. Yet, a random selection of EGUs would have required testing by only about 15% of the EGUs equipped with ACI. UARG Comments at 91 (JA__). In addition, an inordinately high percentage of the EGUs chosen for mercury testing were equipped with fabric filters—a technology known to produce lower mercury emissions. EPA selected the best performing units for mercury testing just as it told OMB. Id. The likely reason for EPA’s confusion regarding the MACT floor for mercury is the significant, widespread conversion error EPA made in analyzing the ICR mercury emissions data. See supra p.20. Based on a 1,000-fold calculational error, EPA erroneously believed that units that were not selected in the ICR testing 60 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 101 of 177 phase controlled mercury better than those that were selected. Correcting EPA’s conversion error confirms that EPA actually selected the best performing mercury units for ICR sampling. See UARG Comments at 90 (JA__). Nevertheless, in the final rule, EPA stuck to its claim that the ICR testing was not designed to require testing by the top performing units for mercury.67 As a result, the existing source mercury standard for EGUs burning high-BTU coals is patently unlawful and must be set aside. See Sierra Club v. EPA, 167 F.3d 658, 664 (D.C. Cir. 1999) (“[This cursory] exercise highlights the need for additional explanation,” for “[w]ith these numbers, EPA’s method looks hopelessly irrational.”). C. EPA Arbitrarily and Capriciously Refused To Set Alternative Health-Based Limits Under §112(d)(4) for Acid Gas HAPs. Congress wrote §112(d)(4) to avoid situations where the mechanical setting of §112(d) MACT limits would result in emission standards more stringent than necessary to protect public health. CAA §112(d)(4) provides: With respect to pollutants for which a health threshold has been established, the Administrator may consider such threshold level, with an ample margin of safety, when establishing emission standards under this subsection. 67 EPA, RTC on Proposed Rule, Vol. 1 at 575 (Dec. 2011), EPA-HQ-OAR2009-0234-20126 (JA__). 61 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 102 of 177 The acid gas HAPs emitted by EGUs are non-carcinogens that have EPA- or state-defined health thresholds known as RfCs.68 EPA defines an RfC as “an estimate…of a continuous [inhalation] exposure to the human population (including sensitive subgroups) that is likely to be without appreciable risk of deleterious effects during a lifetime.”69 Thus, public health is protected with an ample margin of safety when long-term exposures are below the RfC. EPA and industry modeling has consistently shown that worst case exposures to EGU acid gas HAPs are an order of magnitude or more below the RfCs. See supra note 59. Yet, EPA refused to set an alternative §112(d)(4) standard, asserting that §112(d)(4) provided EPA unfettered authority to consider other “factors not specifically enumerated” in that subsection when deciding whether to set a §112(d)(4) standard.” RTC on Proposed Rule, Vol. 1 at 11 (JA__). EPA then recited general, unquantified concerns about “potential cumulative public health and environmental effects” and PM2.5 co-benefits as grounds for refusing to promulgate §112(d)(4) limits. 77 FR at 9405/3 (JA__); see supra pp.53-54. A rule must be set aside where the agency has “relied on factors which Congress has not intended it to consider,” or has “offered an explanation for its decision that runs counter to the evidence before the agency.” Motor Vehicle Mfrs. 68 69 See UARG Comments at 114 (JA__). 55 FR 39321, 39321/3 (Sept. 26, 1990) (JA__). 62 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 103 of 177 Ass’n, 463 U.S. at 43. Here, there is undisputed evidence that public exposure to acid gas HAP emissions from EGUs were 10% or less of the RfC. If, as EPA argues, EGUs must be regulated like any other source category, then EPA had ample justification for establishing alternative health-based limits under §112(d)(4). EPA abused its discretion by refusing to consider such limits based on unquantified concerns about environmental effects and effects of PM2.5. D. The Startup and Shutdown Work Practice Standards Were Promulgated with Inadequate Notice and Are Arbitrary and Capricious. EPA proposed numerical emission limitations under §112(d) that would have applied “at all times.” 76 FR at 25028/1 (JA__). In the final rule, EPA agreed with commenters that it lacked data sufficient to set emissions standards that apply during periods of unit startup and shutdown. 77 FR at 9381/1-2 (JA__). Instead, EPA promulgated work practice standards for those periods under CAA §112(h), as commenters urged. 40 C.F.R. §63.10042 and Part 63, Subpart UUUUU, Table 3, 77 FR at 9486/3, 9493-94 (JA__, __-__); RTC on Proposed Rule, Vol. 2 at 418-419 (JA__-__). However, rather than use the definitions of “startup” and “shutdown” EPA proposed to apply to the rule (i.e., those in the general provisions at 40 C.F.R. §63.2), or to specify standards consistent with comments it received, EPA promulgated new definitions of “startup” and “shutdown” and more detailed requirements. See Joint Brief of Petitioners, UARG 63 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 104 of 177 v. EPA, No. 12-1166 (D.C. Cir. filed Oct. 23, 2012) at Statement of the Case V.C (describing the final Subpart UUUUU work practice standards and problems with them). The definitions and standards EPA promulgated do not adequately reflect how EGUs actually start up and shut down their emissions control equipment, or take into account all types of units to which they would apply and the fuels those units can (or have available to) combust.70 Id. Once source-specific characteristics are considered, EPA’s startup and shutdown provisions are plainly arbitrary and lack any record support. Moreover, commenters could not have anticipated the specific details in EPA’s final rule, as they were not proposed. EPA’s attempts to tie the details of its new definitions and associated requirements to its original notice, and the comments received on it, fail. Id. Because the notice EPA provided was not sufficient to support the details of the final work practice standards, they must be vacated and remanded for further notice and comment. Fertilizer Inst. v. EPA, 935 70 For example, the final work practice standards require use of either natural gas or distillate oil for ignition and require engagement of emissions controls when any other fuel is combusted. 40 C.F.R. Part 63, Subpart UUUUU, Table 3, 77 FR at 9493-94 (JA__-__). Petitioners Edgecombe and Spruance operate coal-fired stoker boilers that were not designed with auxiliary burners and, thus, have no startup fuel. Rather, diesel-soaked coal and wood are used to ignite the coal during startup. Neither facility is equipped to burn natural gas or distillate oil, and neither has the internal or external infrastructure to do so. Edgecombe & Spruance Petition for Reconsideration at 4 (Apr. 27, 2012), EPA-HQ-OAR-2009-023420194 (JA__). 64 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 105 of 177 F.2d 1303, 1311 (D.C. Cir. 1991) (requiring a new round of notice-and-comment rulemaking if it would provide commenters with “their first occasion to offer new and different criticisms which the agency might find convincing”)(internal quotation marks omitted); see also Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 549 (D.C. Cir. 1983) (describing the more exacting notice requirements of §307(d)). E. EPA’s Denial of UARG’s Delisting Petition Was Unlawful. EPA relies on the same flawed factual bases to deny UARG’s §112(c)(9) petition to delist coal-fired EGUs from the §112(c) list of major source categories as EPA does in making its “appropriate and necessary” determination. See 77 FR at 9364-66 (JA__-__); supra Argument I.C. EPA’s summary denial does not follow its own memorandum discussing the delisting process,71 and was issued without any prior notice or opportunity for public comment. EPA also appears to deny UARG’s delisting petition on the grounds that the petition was deficient because UARG only sought to delist coal-fired EGUs and not oil-fired units. Id. at 9364/2 (JA__). This reason for denial must fail. CAA §112(n)(1)(A) requires EPA to evaluate all “fossil-fuel-fired” EGUs to determine if further regulation is appropriate and necessary. 71 EPA’s Utility Study and Memorandum from Sally Shaver, EPA, to Potential Petitioners Seeking Delisting of HAPs or Source Categories, Information on EPA’s Delisting Process (undated) (JA__). 65 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 106 of 177 subsequent December 2000 regulatory determination divided the universe of “fossil-fuel fired” EGUs into three categories: coal-fired, oil-fired, and gas-fired. In 2000, EPA decided not to regulate gas-fired EGUs but to regulate coal- and oilfired EGUs under §112(d) for different factual reasons. 65 FR at 79831/1 (JA__). Just as EPA can decide not to regulate gas-fired EGUs it can also legally decide not to regulate coal-fired EGUs. For these reasons, the Court should reject EPA’s factual and legal claims and return UARG’s delisting petition to EPA for further consideration. CONCLUSION For the foregoing reasons, the Court should vacate the MATS rule. Dated: October 23, 2012 Respectfully submitted, /s/ F. William Brownell F. William Brownell Lauren E. Freeman Lee B. Zeugin Elizabeth L. Horner (Admitted only in VA; DC application pending) HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 (202) 955-1500 bbrownell@hunton.com /s/ Neil D. Gordon Bill Schuette Attorney General John J. Bursch Solicitor General S. Peter Manning Neil D. Gordon Brian J. Negele Assistant Attorneys General Environment, Natural Resources, and Agriculture Division Office of the Attorney General of Michigan 525 W. Ottawa Street P.O. Box 30755 Lansing, MI 48909 (517) 373-7540 manningp@michigan.gov Counsel for Utility Air Regulatory Group 66 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 107 of 177 gordonnl@michigan.gov negeleb@michigan.gov Counsel for the State of Michigan /s/ Peter S. Glaser Peter S. Glaser George Y. Sugiyama Michael H. Higgins TROUTMAN SANDERS LLP 401 Ninth Street, N.W. Suite 1000 Washington, D.C. 20004 (202) 274-2998 peter.glaser@troutmansanders.com /s/ Luther Strange Luther Strange Attorney General State of Alabama Office of the Attorney General 501 Washington Avenue Montgomery, AL 36130 (334) 242-7445 Counsel for the State of Alabama Counsel for National Mining Association /s/ David B. Rivkin, Jr. David B. Rivkin, Jr. Lee A. Casey Mark W. DeLaquil Andrew M. Grossman BAKER & HOSTETLER LLP Washington Square, Suite 1100 1050 Connecticut Avenue, N.W. Washington, D.C. 20036-5304 (202) 861-1500 drivkin@bakerlaw.com lcasey@bakerlaw.com mdelaquil@bakerlaw.com agrossman@bakerlaw.com /s/ Steven E. Mulder Michael C. Geraghty Attorney General Steven E. Mulder State of Alaska 1031 W. 4th Avenue, Suite 200 Anchorage, AK 99501-1994 Counsel for the State of Alaska Counsel for National Black Chamber of Commerce and Institute for Liberty 67 USCA Case #12-1100 Document #1401252 /s/ David M. Flannery David M. Flannery Gale Lea Rubrecht Kathy G. Beckett Edward L. Kropp JACKSON KELLY PLLC 500 Lee Street, East, Suite 1600 P.O. Box 553 Charleston, WV 25322-553 (304) 340-1000 dmflannery@jacksonkelly.com galelea@jacksonkelly.com kbeckett@jacksonkelly.com skropp@jacksonkelly.com Filed: 10/23/2012 Page 108 of 177 /s/ Joseph P. Mikitish Thomas Horne Arizona Attorney General Joseph P. Mikitish James T. Skardon Assistant Attorneys General Environmental Enforcement Section 1275 West Washington Phoenix, AZ 85007 (602) 542-8553 Joseph.mikitish@azag.gov Counsel for the State of Arizona Counsel for Midwest Ozone Group /s/ Leslie Sue Ritts Leslie Sue Ritts RITTS LAW GROUP, PLLC The Carriage House 620 Fort Williams Parkway Alexandria, VA 22304 (703) 823-2292 LSRitts@rittslawgroup.com Counsel for American Public Power Association /s/ Kendra Akin Jones Dustin McDaniel Arkansas Attorney General Kendra Akin Jones Assistant Attorney General Charles L. Moulton Senior Assistant Attorney General Arkansas Attorney General 323 Center Street, Suite 400 Little Rock, AR 72201 (501) 682-2007 kendra.jones@arkansasag.gov charles.moulton@arkansasag.gov Counsel for the State of Arkansas, ex rel. Dustin McDaniel, Attorney General 68 USCA Case #12-1100 Document #1401252 /s/ Peter S. Glaser Peter S. Glaser George Y. Sugiyama Michael H. Higgins TROUTMAN SANDERS LLP 401 Ninth Street, N.W. Suite 1000 Washington, D.C. 20001 (202) 274-2998 peter.glaser@troutmansanders.com Filed: 10/23/2012 Page 109 of 177 /s/ Jonathan A. Glogau Pamela Jo Bondi Attorney General of Florida Jonathan A. Glogau The Capitol, PL-01 Tallahassee, FL 32399-1050 Counsel for the State of Florida Counsel for Peabody Energy Corporation 69 USCA Case #12-1100 Document #1401252 /s/ David M. Flannery David M. Flannery Gale Lea Rubrecht Kathy G. Beckett Edward L. Kropp JACKSON KELLY PLLC 500 Lee Street, East, Suite 1600 P.O. Box 553 Charleston, WV 25322-553 (304) 340-1000 dmflannery@jacksonkelly.com galelea@jacksonkelly.com kbeckett@jacksonkelly.com skropp@jacksonkelly.com Filed: 10/23/2012 Page 110 of 177 /s/ Lawrence G. Wasden Lawrence G. Wasden Idaho Attorney General PO Box 83720 Boise, ID 83720-0010 Counsel for the State of Idaho Counsel for West Virginia Chamber of Commerce, Inc., Georgia Association of Manufacturers, Inc., Indiana Chamber of Commerce, Inc., Indiana Coal Council, Inc., Kentucky Chamber of Commerce, Inc., Kentucky Coal Association, Inc., North Carolina Chamber, Ohio Chamber of Commerce, Pennsylvania Coal Association, South Carolina Chamber of Commerce, The Virginia Chamber of Commerce, The Virginia Coal Association, Incorporated, , West Virginia Coal Association, Inc., and Wisconsin Industrial Energy Group, Inc. 70 USCA Case #12-1100 Document #1401252 /s/ Eugene M. Trisko Grant Crandall Arthur Traynor, III UNITED MINE WORKERS OF AMERICA 18354 Quantico Gateway Drive Suite 200 Triangle, VA 22172 (703) 291-2457 gcrandall@umwa.org atraynor@umwa.org Eugene M. Trisko LAW OFFICES OF EUGENE M. 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Chanay Deputy Attorney General, Civil Litigation Division Office of the Attorney General of Kansas 120 SW 10th Avenue, 3rd Floor Topeka, KS 66612-1597 (785) 368-8435 jeff.chanay@ksag.org Henry V. Nickel HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, NW Washington, DC 20037 (202) 955-1500 hnickel@hunton.com George P. Sibley, III HUNTON & WILLIAMS LLP Riverfront Plaza, East Tower 951 E. Byrd Street Richmond, VA 23221 (804) 788-8200 gsibley@hunton.com Counsel for the State of Kansas 72 USCA Case #12-1100 Document #1401252 /s/ Eric A. Groten Eric A. Groten VINSON & ELKINS LLP 2801 Via Fortuna, Suite 100 Austin, TX 78746-7568 (512) 542-8709 egroten@velaw.com Jeremy C. Marwell VINSON & ELKINS LLP 2200 Pennsylvania Avenue, NW Suite 500 West Washington, DC 20037-1701 (202) 639-6507 jmarwell@velaw.com Filed: 10/23/2012 Page 113 of 177 /s/ Harold E. Pizzetta III Harold E. Pizzetta III Assistant Attorney General Director, Civil Litigation Division 550 High Street, Suite 1100 Post Office Box 220 Jackson, MS 39205-0220 (601) 359-3816 hpizz@ago.state.ms.us Counsel for the State of Mississippi Counsel for White Stallion Energy Center, LLC /s/ John A. Riley John A. Riley Christopher C. Thiele BRACEWELL & GIULIANI LLP 111 Congress Avenue, Ste. 2300 Austin, TX 78701-4061 (512) 542-2108 john.riley@bgllp.com chris.thiele@bgllp.com /s/ James R. Layton Chris Koster Attorney General James R. Layton John K. McManus PO Box 899 Jefferson City, MO 65102 (573) 751-1800 James.Layton@ago.mo.gov Counsel for Chase Power Development, LLC Counsel for the State of Missouri 73 USCA Case #12-1100 Document #1401252 /s/ Paul D. Clement Paul D. Clement Nathan A. Sales BANCROFT PLLC 1919 M Street, N.W., Suite 470 Washington, DC 20036 (202) 234-0090 pclement@bancroftpllc.com nsales@bancroftpllc.com Counsel for FirstEnergy Generation Corporation Filed: 10/23/2012 Page 114 of 177 /s/ Katherine J. Spohn Jon Bruning Attorney General of the State of Nebraska Katherine J. Spohn Special Counsel to the Attorney General 2115 State Capitol PO Box 98920 Lincoln, NE 68509 (402) 471-2682 Katie.spohn@nebraska.gov Counsel for the State of Nebraska /s/ Lisa Marie Jaeger Lisa Marie Jaeger BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 (202) 828-5800 lisa.jaeger@bgllp.com Counsel for Edgecombe Genco, LLC and Spruance Genco, LLC /s/ Margaret I. Olson Wayne Stenehjem Attorney General State of North Dakota Margaret I. Olson Assistant Attorney General Office of Attorney General 500 North 9th Street Bismarck, ND 58501-4509 (701) 328-3640 maiolson@nd.gov Counsel for the State of North Dakota 74 USCA Case #12-1100 Document #1401252 /s/ Steven C. Kohl Steven C. Kohl Eugene E. Smary Sarah C. Lindsey WARNER NORCROSS & JUDD LLP 2000 Town Center, Suite 2700 Southfield, Michigan 48075-1318 (248) 784-5000 skohl@wnj.com Counsel for Wolverine Power Supply Cooperative, Inc. Filed: 10/23/2012 Page 115 of 177 /s/ Dale T. Vitale Michael DeWine Attorney General of Ohio Dale T. Vitale Gregg H. Bachmann Cameron F. Simmons Assistant Attorneys General Environmental Enforcement Section 30 E. Broad St., 25th Floor Columbus, OH 43215-3400 (614) 466-2766 dale.vitale@ohioattorneygeneral.gov Counsel for the State of Ohio /s/ E. Scott Pruitt E. Scott Pruitt Oklahoma Attorney General P. Clayton Eubanks Assistant Attorney General Public Protection Unit/Environment Office of the Attorney General of Oklahoma 313 N.E. 21st Street Oklahoma City, OK 73105 (405) 522-8992 fc.docket@oag.ok.gov clayton.eubanks@oag.ok.gov /s/ Robert M. Wolff James D. Schultz General Counsel Gregory E. Dunlap Senior Deputy General Counsel Robert M. Wolff Special Counsel Office of General Counsel 333 Market Street, 17th Floor Harrisburg, PA 17120 (717) 783-6563 Counsel for the Commonwealth of Pennsylvania Counsel for the State of Oklahoma 75 USCA Case #12-1100 Document #1401252 /s/ James Emory Smith, Jr. Alan Wilson Attorney General James Emory Smith, Jr. Assistant Deputy Attorney General Office of the Attorney General P.O. Box 11549 Columbia, SC 29211 (803) 734-3680 agesmith@scag.gov Counsel for the State of South Carolina Filed: 10/23/2012 Page 116 of 177 /s/ Mark Walters Greg Abbott Attorney General of Texas Daniel T. Hodge First Assistant Attorney General John B. Scott Deputy Attorney General for Civil Litigation Jon Niermann Chief, Environmental Protection Division Mark Walters Assistant Attorney General Mary E. Smith Assistant Attorney General Office of the Attorney General of Texas Environmental Protection Division P. O. Box 12548, Capitol Station Austin, TX 78711-2548 (512) 463-2012 mark.walters@texasattorneygeneral.gov mary.smith@texasattorneygeneral.gov Counsel for the State of Texas, Texas Commission on Environmental Quality, Texas Public Utility Commission, and Railroad Commission of Texas /s/ Mark L. Shurtleff Mark L. Shurtleff Utah Attorney General 350 North State Street, #230 Salt Lake City, UT 84114-2320 (801) 538-1191 /s/ Kenneth T. Cuccinelli, II Kenneth T. Cuccinelli, II Attorney General of Virginia 900 East Main Street Richmond, VA 23219 (804) 786-7240 Counsel for the State of Utah Counsel for the Commonwealth of Virginia 76 USCA Case #12-1100 Document #1401252 /s/ Silas B. Taylor Silas B. Taylor Senior Deputy Attorney General Office of the Attorney General of West Virginia State Capitol, Room 26-E Charleston, WV 25305 silastaylor@yahoo.com Counsel for the State of West Virginia Filed: 10/23/2012 Page 117 of 177 /s/ Jay A. Jerde Gregory A. Phillips Wyoming Attorney General Jay A. Jerde Wyoming Deputy Attorney General Office of the Attorney General of Wyoming 123 State Capitol Cheyenne, WY 82002 (307) 777-7841 jay.jerde@wyo.gov Counsel for the State of Wyoming /s/ Brenna Findley Brenna Findley 1007 East Grand Avenue Des Moines, IA 50319 brenna.findley@iowa.gov /s/ Jack Conway Jack Conway Attorney General of Kentucky 700 Capital Avenue, Suite 118 Frankfort, KY 40601 Counsel for Terry E. Branstad, Governor of the State of Iowa on behalf of the People of Iowa Counsel for Jack Conway, Attorney General of Kentucky /s/ Jeffrey R. Holmstead Jeffrey R. Holmstead Sandra Y. Snyder BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 (202) 828-5800 /s/ Katherine L. Vaccaro Bart E. Cassidy Katherine L. Vaccaro MANKO, GOLD, KATCHER & FOX, LLP 401 City Avenue, Suite 500 Bala Cynwyd, PA 19004 (484) 430-5700 Counsel for Tri-State Generation and Transmission Association, Inc. Counsel for ARIPPA 77 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 118 of 177 CERTIFICATE OF COMPLIANCE Pursuant to Rule 32(a)(7)(C) of the Federal Rules of Appellate Procedure and Circuit Rules 32(a)(1) and 32(a)(2)(C), I hereby certify that the foregoing Joint Brief of State, Industry, and Labor Petitioners contains 14,879 words, as counted by a word processing system that includes headings, footnotes, quotations, and citations in the count, and therefore is within the word limit set by the Court. Dated: October 23, 2012 /s/ F. William Brownell USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 119 of 177 CERTIFICATE OF SERVICE I hereby certify that, on this 23rd day of October 2012, a copy of the Joint Brief of State, Industry, and Labor Petitioners was served electronically through the Court’s CM/ECF system on all ECF-registered counsel. /s/ F. William Brownell USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Statutory and Regulatory Addendum Page 120 of 177 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 121 of 177 TABLE OF CONTENTS 1. Clean Air Act § 101(b)(1), 42 U.S.C. § 7401(b)(1) .............. Addendum - 001 2. Clean Air Act § 108(a)(2), 42 U.S.C. § 7408(a)(2)............... Addendum - 003 3. Clean Air Act § 110(a)(2)(D), 42 U.S.C. § 7410(a)(2)(D) ...................................................................... Addendum - 005 4. Clean Air Act § 111, 42 U.S.C. § 7411 ................................. Addendum - 007 5. Clean Air Act § 112(a)-(f), (h)-(i), (n), 42 U.S.C. § 7412(a)-(f), (h)-(i), (n) ........................................................... Addendum - 012 6. Clean Air Act § 115, 42 U.S.C. § 7415 ................................. Addendum – 026 7. Clean Air Act § 211(f)(4), 42 U.S.C. § 7545(f)(4) ............... Addendum - 028 8. Clean Air Act § 304(a), 42 U.S.C. § 7604(a) ........................ Addendum - 031 9. Clean Air Act § 307, 42 U.S.C. § 7607 ................................. Addendum - 032 10. Clean Air Act Amendments of 1970, Pub. L. No. 91-604, §112(a)(1), 84 Stat. 1676, 1685 (1970) .................... Addendum – 037 11. 40 C.F.R. § 60.44 ................................................................... Addendum - 039 12. 40 C.F.R. § 63.2 ..................................................................... Addendum - 041 13. 40 C.F.R. § 63.10042 ............................................................. Addendum – 049 14. 40 C.F.R. Part 63, Subpart UUUUU, Table 3 ....................... Addendum – 055 USCA Case #12-1100 Page 6207 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE Sec. Page 122 of 177 § 7401 Sec. 7548. Study of particulate emissions from motor vehicles. High altitude performance adjustments. Definitions. Omitted. Motor vehicle compliance program fees. Prohibition on production of engines requiring leaded gasoline. Urban bus standards. 7549. 7550. 7551. 7552. 7553. 7554. PART B—AIRCRAFT EMISSION STANDARDS 7571. 7572. 7573. 7574. Establishment of standards. Enforcement of standards. State standards and controls. Definitions. 7581. 7582. Definitions. Requirements applicable to clean-fuel vehicles. Standards for light-duty clean-fuel vehicles. Administration and enforcement as per California standards. Standards for heavy-duty clean-fuel vehicles (GVWR above 8,500 up to 26,000 lbs.). Centrally fueled fleets. Vehicle conversions. Federal agency fleets. California pilot test program. General provisions. 7585. 7586. 7587. 7588. 7589. 7590. SUBCHAPTER III—GENERAL PROVISIONS 7601. 7602. 7603. 7604. 7605. 7606. 7607. 7608. 7609. 7610. 7611. 7612. 7613. 7614. 7615. 7616. 7617. 7618. 7619. 7620. 7621. 7622. 7623. 7624. 7625. 7625–1. 7625a. 7626. 7627. 7628. Administration. Definitions. Emergency powers. Citizen suits. Representation in litigation. Federal procurement. Administrative proceedings and judicial review. Mandatory licensing. Policy review. Other authority. Records and audit. Economic impact analyses. Repealed. Labor standards. Separability. Sewage treatment grants. Economic impact assessment. Repealed. Air quality monitoring. Standardized air quality modeling. Employment effects. Employee protection. Repealed. Cost of vapor recovery equipment. Vapor recovery for small business marketers of petroleum products. Exemptions for certain territories. Statutory construction. Authorization of appropriations. Air pollution from Outer Continental Shelf activities. Demonstration grant program for local governments. SUBCHAPTER IV—NOISE POLLUTION 7641. 7642. Noise abatement. Authorization of appropriations. SUBCHAPTER IV–A—ACID DEPOSITION CONTROL 7651. 7651a. 7651b. 7651c. 7651d. 7651f. 7651g. 7651h. 7651i. 7651j. 7651k. 7651l. 7651m. 7651n. 7651o. Allowances for States with emissions rates at or below 0.80 lbs/mmBtu. Nitrogen oxides emission reduction program. Permits and compliance plans. Repowered sources. Election for additional sources. Excess emissions penalty. Monitoring, reporting, and recordkeeping requirements. General compliance with other provisions. Enforcement. Clean coal technology regulatory incentives. Contingency guarantee, auctions, reserve. SUBCHAPTER V—PERMITS PART C—CLEAN FUEL VEHICLES 7583. 7584. 7651e. Findings and purposes. Definitions. Sulfur dioxide allowance program for existing and new units. Phase I sulfur dioxide requirements. Phase II sulfur dioxide requirements. 7661. 7661a. 7661b. 7661c. 7661d. 7661e. 7661f. Definitions. Permit programs. Permit applications. Permit requirements and conditions. Notification to Administrator and contiguous States. Other authorities. Small business stationary source technical and environmental compliance assistance program. SUBCHAPTER VI—STRATOSPHERIC OZONE PROTECTION 7671. 7671a. 7671b. 7671c. 7671d. 7671e. 7671f. 7671g. 7671h. 7671i. 7671j. 7671k. 7671l. 7671m. 7671n. 7671o. 7671p. 7671q. Definitions. Listing of class I and class II substances. Monitoring and reporting requirements. Phase-out of production and consumption of class I substances. Phase-out of production and consumption of class II substances. Accelerated schedule. Exchange authority. National recycling and emission reduction program. Servicing of motor vehicle air conditioners. Nonessential products containing chlorofluorocarbons. Labeling. Safe alternatives policy. Federal procurement. Relationship to other laws. Authority of Administrator. Transfers among Parties to Montreal Protocol. International cooperation. Miscellaneous provisions. CODIFICATION Act July 14, 1955, ch. 360, 69 Stat. 322, as amended, known as the Clean Air Act, which was formerly classified to chapter 15B (§ 1857 et seq.) of this title, was completely revised by Pub. L. 95–95, Aug. 7, 1977, 91 Stat. 685, and was reclassified to this chapter. SUBCHAPTER I—PROGRAMS AND ACTIVITIES PART A—AIR QUALITY AND EMISSION LIMITATIONS AMENDMENTS 1977—Pub. L. 95–95, title I, § 117(a), Aug. 7, 1977, 91 Stat. 712, designated sections 7401 to 7428 of this title as part A. § 7401. Congressional findings and declaration of purpose (a) Findings The Congress finds— (1) that the predominant part of the Nation’s population is located in its rapidly expanding metropolitan and other urban areas, which Addendum – 001 CAA § 101 USCA Case #12-1100 § 7401 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE generally cross the boundary lines of local jurisdictions and often extend into two or more States; (2) that the growth in the amount and complexity of air pollution brought about by urbanization, industrial development, and the increasing use of motor vehicles, has resulted in mounting dangers to the public health and welfare, including injury to agricultural crops and livestock, damage to and the deterioration of property, and hazards to air and ground transportation; (3) that air pollution prevention (that is, the reduction or elimination, through any measures, of the amount of pollutants produced or created at the source) and air pollution control at its source is the primary responsibility of States and local governments; and (4) that Federal financial assistance and leadership is essential for the development of cooperative Federal, State, regional, and local programs to prevent and control air pollution. (b) Declaration The purposes of this subchapter are— (1) to protect and enhance the quality of the Nation’s air resources so as to promote the public health and welfare and the productive capacity of its population; (2) to initiate and accelerate a national research and development program to achieve the prevention and control of air pollution; (3) to provide technical and financial assistance to State and local governments in connection with the development and execution of their air pollution prevention and control programs; and (4) to encourage and assist the development and operation of regional air pollution prevention and control programs. (c) Pollution prevention A primary goal of this chapter is to encourage or otherwise promote reasonable Federal, State, and local governmental actions, consistent with the provisions of this chapter, for pollution prevention. (July 14, 1955, ch. 360, title I, § 101, formerly § 1, as added Pub. L. 88–206, § 1, Dec. 17, 1963, 77 Stat. 392; renumbered § 101 and amended Pub. L. 89–272, title I, § 101(2), (3), Oct. 20, 1965, 79 Stat. 992; Pub. L. 90–148, § 2, Nov. 21, 1967, 81 Stat. 485; Pub. L. 101–549, title I, § 108(k), Nov. 15, 1990, 104 Stat. 2468.) CODIFICATION Section was formerly classified to section 1857 of this title. PRIOR PROVISIONS Provisions similar to those in this section were contained in a prior section 1857 of this title, act of July 14, 1955, ch. 360, § 1, 69 Stat. 322, prior to the general amendment of this chapter by Pub. L. 88–206. AMENDMENTS 1990—Subsec. (a)(3). Pub. L. 101–549, § 108(k)(1), amended par. (3) generally. Prior to amendment, par. (3) read as follows: ‘‘that the prevention and control of air pollution at its source is the primary responsibility of States and local governments; and’’. Subsec. (b)(4). Pub. L. 101–549, § 108(k)(2), inserted ‘‘prevention and’’ after ‘‘pollution’’. Page 123 of 177 Page 6208 Subsec. (c). Pub. L. 101–549, § 108(k)(3), added subsec. (c). 1967—Subsec. (b)(1). Pub. L. 90–148 inserted ‘‘and enhance the quality of’’ after ‘‘to protect’’. 1965—Subsec. (b). Pub. L. 89–272 substituted ‘‘this title’’ for ‘‘this Act’’, which for purposes of codification has been changed to ‘‘this subchapter’’. EFFECTIVE DATE OF 1990 AMENDMENT Section 711(b) of Pub. L. 101–549 provided that: ‘‘(1) Except as otherwise expressly provided, the amendments made by this Act [see Tables for classification] shall be effective on the date of enactment of this Act [Nov. 15, 1990]. ‘‘(2) The Administrator’s authority to assess civil penalties under section 205(c) of the Clean Air Act [42 U.S.C. 7524(c)], as amended by this Act, shall apply to violations that occur or continue on or after the date of enactment of this Act. Civil penalties for violations that occur prior to such date and do not continue after such date shall be assessed in accordance with the provisions of the Clean Air Act [42 U.S.C. 7401 et seq.] in effect immediately prior to the date of enactment of this Act. ‘‘(3) The civil penalties prescribed under sections 205(a) and 211(d)(1) of the Clean Air Act [42 U.S.C. 7524(a), 7545(d)(1)], as amended by this Act, shall apply to violations that occur on or after the date of enactment of this Act. Violations that occur prior to such date shall be subject to the civil penalty provisions prescribed in sections 205(a) and 211(d) of the Clean Air Act in effect immediately prior to the enactment of this Act. The injunctive authority prescribed under section 211(d)(2) of the Clean Air Act, as amended by this Act, shall apply to violations that occur or continue on or after the date of enactment of this Act. ‘‘(4) For purposes of paragraphs (2) and (3), where the date of a violation cannot be determined it will be assumed to be the date on which the violation is discovered.’’ EFFECTIVE DATE OF 1977 AMENDMENT; PENDING ACTIONS; CONTINUATION OF RULES, CONTRACTS, AUTHORIZATIONS, ETC.; IMPLEMENTATION PLANS Section 406 of Pub. L. 95–95, as amended by Pub. L. 95–190, § 14(b)(6), Nov. 16, 1977, 91 Stat. 1405, provided that: ‘‘(a) No suit, action, or other proceeding lawfully commenced by or against the Administrator or any other officer or employee of the United States in his official capacity or in relation to the discharge of his official duties under the Clean Air Act [this chapter], as in effect immediately prior to the date of enactment of this Act [Aug. 7, 1977] shall abate by reason of the taking effect of the amendments made by this Act [see Short Title of 1977 Amendment note below]. The court may, on its own motion or that of any party made at any time within twelve months after such taking effect, allow the same to be maintained by or against the Administrator or such officer or employee. ‘‘(b) All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or other actions duly issued, made, or taken by or pursuant to the Clean Air Act [this chapter], as in effect immediately prior to the date of enactment of this Act [Aug. 7, 1977], and pertaining to any functions, powers, requirements, and duties under the Clean Air Act, as in effect immediately prior to the date of enactment of this Act, and not suspended by the Administrator or the courts, shall continue in full force and effect after the date of enactment of this Act until modified or rescinded in accordance with the Clean Air Act as amended by this Act [see Short Title of 1977 Amendment note below]. ‘‘(c) Nothing in this Act [see Short Title of 1977 Amendment note below] nor any action taken pursuant to this Act shall in any way affect any requirement of an approved implementation plan in effect under section 110 of the Clean Air Act [section 7410 of this title] Addendum – 002 USCA Case #12-1100 Page 6227 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE (designated in subsection (a)) which consists of the PM2.5 monitors necessary to implement the national ambient air quality standards is established by December 31, 1999. ‘‘(c)(1) The Governors shall be required to submit designations referred to in section 107(d)(1) of the Clean Air Act [42 U.S.C. 7407(d)(1)] for each area following promulgation of the July 1997 PM2.5 national ambient air quality standard within 1 year after receipt of 3 years of air quality monitoring data performed in accordance with any applicable Federal reference methods for the relevant areas. Only data from the monitoring network designated in subsection (a) and other Federal reference method PM2.5 monitors shall be considered for such designations. Nothing in the previous sentence shall be construed as affecting the Governor’s authority to designate an area initially as nonattainment, and the Administrator’s authority to promulgate the designation of an area as nonattainment, under section 107(d)(1) of the Clean Air Act, based on its contribution to ambient air quality in a nearby nonattainment area. ‘‘(2) For any area designated as nonattainment for the July 1997 PM2.5 national ambient air quality standard in accordance with the schedule set forth in this section, notwithstanding the time limit prescribed in paragraph (2) of section 169B(e) of the Clean Air Act [42 U.S.C. 7492(e)(2)], the Administrator shall require State implementation plan revisions referred to in such paragraph (2) to be submitted at the same time as State implementation plan revisions referred to in section 172 of the Clean Air Act [42 U.S.C. 7502] implementing the revised national ambient air quality standard for fine particulate matter are required to be submitted. For any area designated as attainment or unclassifiable for such standard, the Administrator shall require the State implementation plan revisions referred to in such paragraph (2) to be submitted 1 year after the area has been so designated. The preceding provisions of this paragraph shall not preclude the implementation of the agreements and recommendations set forth in the Grand Canyon Visibility Transport Commission Report dated June 1996. ‘‘(d) The Administrator shall promulgate the designations referred to in section 107(d)(1) of the Clean Air Act [42 U.S.C. 7407(d)(1)] for each area following promulgation of the July 1997 PM2.5 national ambient air quality standard by the earlier of 1 year after the initial designations required under subsection (c)(1) are required to be submitted or December 31, 2005. ‘‘(e) FIELD STUDY.—Not later than 2 years after the date of enactment of the SAFETEA–LU [Aug. 10, 2005], the Administrator shall— ‘‘(1) conduct a field study of the ability of the PM2.5 Federal Reference Method to differentiate those particles that are larger than 2.5 micrometers in diameter; ‘‘(2) develop a Federal reference method to measure directly particles that are larger than 2.5 micrometers in diameter without reliance on subtracting from coarse particle measurements those particles that are equal to or smaller than 2.5 micrometers in diameter; ‘‘(3) develop a method of measuring the composition of coarse particles; and ‘‘(4) submit a report on the study and responsibilities of the Administrator under paragraphs (1) through (3) to— ‘‘(A) the Committee on Energy and Commerce of the House of Representatives; and ‘‘(B) the Committee on Environment and Public Works of the Senate. ‘‘SEC. 6103. OZONE DESIGNATION REQUIREMENTS. ‘‘(a) The Governors shall be required to submit the designations referred to in section 107(d)(1) of the Clean Air Act [42 U.S.C. 7407(d)(1)] within 2 years following the promulgation of the July 1997 ozone national ambient air quality standards. ‘‘(b) The Administrator shall promulgate final designations no later than 1 year after the designations re- Page 124 of 177 § 7408 quired under subsection (a) are required to be submitted. ‘‘SEC. 6104. ADDITIONAL PROVISIONS. ‘‘Nothing in sections 6101 through 6103 shall be construed by the Administrator of Environmental Protection Agency or any court, State, or person to affect any pending litigation or to be a ratification of the ozone or PM2.5 standards.’’ PENDING ACTIONS AND PROCEEDINGS Suits, actions, and other proceedings lawfully commenced by or against the Administrator or any other officer or employee of the United States in his official capacity or in relation to the discharge of his official duties under act July 14, 1955, the Clean Air Act, as in effect immediately prior to the enactment of Pub. L. 95–95 [Aug. 7, 1977], not to abate by reason of the taking effect of Pub. L. 95–95, see section 406(a) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. MODIFICATION OR RESCISSION OF RULES, REGULATIONS, DETERMINATIONS, CONTRACTS, CERTIFIORDERS, CATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER ACTIONS All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect immediately prior to the date of enactment of Pub. L. 95–95 [Aug. 7, 1977] to continue in full force and effect until modified or rescinded in accordance with act July 14, 1955, as amended by Pub. L. 95–95 [this chapter], see section 406(b) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. § 7408. Air quality criteria and control techniques (a) Air pollutant list; publication and revision by Administrator; issuance of air quality criteria for air pollutants (1) For the purpose of establishing national primary and secondary ambient air quality standards, the Administrator shall within 30 days after December 31, 1970, publish, and shall from time to time thereafter revise, a list which includes each air pollutant— (A) emissions of which, in his judgment, cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare; (B) the presence of which in the ambient air results from numerous or diverse mobile or stationary sources; and (C) for which air quality criteria had not been issued before December 31, 1970 but for which he plans to issue air quality criteria under this section. (2) The Administrator shall issue air quality criteria for an air pollutant within 12 months after he has included such pollutant in a list under paragraph (1). Air quality criteria for an air pollutant shall accurately reflect the latest scientific knowledge useful in indicating the kind and extent of all identifiable effects on public health or welfare which may be expected from the presence of such pollutant in the ambient air, in varying quantities. The criteria for an air pollutant, to the extent practicable, shall include information on— (A) those variable factors (including atmospheric conditions) which of themselves or in Addendum – 003 CAA § 108 USCA Case #12-1100 § 7408 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE combination with other factors may alter the effects on public health or welfare of such air pollutant; (B) the types of air pollutants which, when present in the atmosphere, may interact with such pollutant to produce an adverse effect on public health or welfare; and (C) any known or anticipated adverse effects on welfare. (b) Issuance by Administrator of information on air pollution control techniques; standing consulting committees for air pollutants; establishment; membership (1) Simultaneously with the issuance of criteria under subsection (a) of this section, the Administrator shall, after consultation with appropriate advisory committees and Federal departments and agencies, issue to the States and appropriate air pollution control agencies information on air pollution control techniques, which information shall include data relating to the cost of installation and operation, energy requirements, emission reduction benefits, and environmental impact of the emission control technology. Such information shall include such data as are available on available technology and alternative methods of prevention and control of air pollution. Such information shall also include data on alternative fuels, processes, and operating methods which will result in elimination or significant reduction of emissions. (2) In order to assist in the development of information on pollution control techniques, the Administrator may establish a standing consulting committee for each air pollutant included in a list published pursuant to subsection (a)(1) of this section, which shall be comprised of technically qualified individuals representative of State and local governments, industry, and the academic community. Each such committee shall submit, as appropriate, to the Administrator information related to that required by paragraph (1). (c) Review, modification, and reissuance of criteria or information The Administrator shall from time to time review, and, as appropriate, modify, and reissue any criteria or information on control techniques issued pursuant to this section. Not later than six months after August 7, 1977, the Administrator shall revise and reissue criteria relating to concentrations of NO2 over such period (not more than three hours) as he deems appropriate. Such criteria shall include a discussion of nitric and nitrous acids, nitrites, nitrates, nitrosamines, and other carcinogenic and potentially carcinogenic derivatives of oxides of nitrogen. (d) Publication in Federal Register; availability of copies for general public The issuance of air quality criteria and information on air pollution control techniques shall be announced in the Federal Register and copies shall be made available to the general public. (e) Transportation planning and guidelines The Administrator shall, after consultation with the Secretary of Transportation, and after providing public notice and opportunity for comment, and with State and local officials, Page 125 of 177 Page 6228 within nine months after November 15, 1990,1 and periodically thereafter as necessary to maintain a continuous transportation-air quality planning process, update the June 1978 Transportation-Air Quality Planning Guidelines and publish guidance on the development and implementation of transportation and other measures necessary to demonstrate and maintain attainment of national ambient air quality standards. Such guidelines shall include information on— (1) methods to identify and evaluate alternative planning and control activities; (2) methods of reviewing plans on a regular basis as conditions change or new information is presented; (3) identification of funds and other resources necessary to implement the plan, including interagency agreements on providing such funds and resources; (4) methods to assure participation by the public in all phases of the planning process; and (5) such other methods as the Administrator determines necessary to carry out a continuous planning process. (f) Information regarding processes, procedures, and methods to reduce or control pollutants in transportation; reduction of mobile source related pollutants; reduction of impact on public health (1) The Administrator shall publish and make available to appropriate Federal, State, and local environmental and transportation agencies not later than one year after November 15, 1990, and from time to time thereafter— (A) information prepared, as appropriate, in consultation with the Secretary of Transportation, and after providing public notice and opportunity for comment, regarding the formulation and emission reduction potential of transportation control measures related to criteria pollutants and their precursors, including, but not limited to— (i) programs for improved public transit; (ii) restriction of certain roads or lanes to, or construction of such roads or lanes for use by, passenger buses or high occupancy vehicles; (iii) employer-based transportation management plans, including incentives; (iv) trip-reduction ordinances; (v) traffic flow improvement programs that achieve emission reductions; (vi) fringe and transportation corridor parking facilities serving multiple occupancy vehicle programs or transit service; (vii) programs to limit or restrict vehicle use in downtown areas or other areas of emission concentration particularly during periods of peak use; (viii) programs for the provision of all forms of high-occupancy, shared-ride services; (ix) programs to limit portions of road surfaces or certain sections of the metropolitan area to the use of non-motorized vehicles or pedestrian use, both as to time and place; (x) programs for secure bicycle storage facilities and other facilities, including bicy1 See Codification note below. Addendum – 004 USCA Case #12-1100 Page 6231 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE amended Pub. L. 95–95, title I, § 106, Aug. 7, 1977, 91 Stat. 691.) CODIFICATION Section was formerly classified to section 1857c–4 of this title. PRIOR PROVISIONS A prior section 109 of act July 14, 1955, was renumbered section 116 by Pub. L. 91–604 and is classified to section 7416 of this title. AMENDMENTS Page 126 of 177 § 7410 seq.] which may be more effective than secondary standards in preventing or mitigating such effects. ‘‘(b) SUBMISSION TO CONGRESS; COMMENTS; AUTHORIZATION.—(1) The report shall be transmitted to the Congress not later than 3 years after the date of enactment of the Clean Air Act Amendments of 1990 [Nov. 15, 1990]. ‘‘(2) At least 90 days before issuing a report the Administrator shall provide an opportunity for public comment on the proposed report. The Administrator shall include in the final report a summary of the comments received on the proposed report. ‘‘(3) There are authorized to be appropriated such sums as are necessary to carry out this section.’’ 1977—Subsec. (c). Pub. L. 95–95, § 106(b), added subsec. (c). Subsec. (d). Pub. L. 95–95, § 106(a), added subsec. (d). § 7410. State implementation plans for national primary and secondary ambient air quality standards EFFECTIVE DATE OF 1977 AMENDMENT (a) Adoption of plan by State; submission to Administrator; content of plan; revision; new sources; indirect source review program; supplemental or intermittent control systems (1) Each State shall, after reasonable notice and public hearings, adopt and submit to the Administrator, within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof) under section 7409 of this title for any air pollutant, a plan which provides for implementation, maintenance, and enforcement of such primary standard in each air quality control region (or portion thereof) within such State. In addition, such State shall adopt and submit to the Administrator (either as a part of a plan submitted under the preceding sentence or separately) within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national ambient air quality secondary standard (or revision thereof), a plan which provides for implementation, maintenance, and enforcement of such secondary standard in each air quality control region (or portion thereof) within such State. Unless a separate public hearing is provided, each State shall consider its plan implementing such secondary standard at the hearing required by the first sentence of this paragraph. (2) Each implementation plan submitted by a State under this chapter shall be adopted by the State after reasonable notice and public hearing. Each such plan shall— (A) include enforceable emission limitations and other control measures, means, or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance, as may be necessary or appropriate to meet the applicable requirements of this chapter; (B) provide for establishment and operation of appropriate devices, methods, systems, and procedures necessary to— (i) monitor, compile, and analyze data on ambient air quality, and (ii) upon request, make such data available to the Administrator; Amendment by Pub. L. 95–95 effective Aug. 7, 1977, except as otherwise expressly provided, see section 406(d) of Pub. L. 95–95, set out as a note under section 7401 of this title. MODIFICATION OR RESCISSION OF RULES, REGULATIONS, DETERMINATIONS, CONTRACTS, CERTIFIORDERS, CATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER ACTIONS All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect immediately prior to the date of enactment of Pub. L. 95–95 [Aug. 7, 1977] to continue in full force and effect until modified or rescinded in accordance with act July 14, 1955, as amended by Pub. L. 95–95 [this chapter], see section 406(b) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. TERMINATION OF ADVISORY COMMITTEES Advisory committees established after Jan. 5, 1973, to terminate not later than the expiration of the 2-year period beginning on the date of their establishment, unless, in the case of a committee established by the President or an officer of the Federal Government, such committee is renewed by appropriate action prior to the expiration of such 2-year period, or in the case of a committee established by the Congress, its duration is otherwise provided for by law. See section 14 of Pub. L. 92–463, Oct. 6, 1972, 86 Stat. 776, set out in the Appendix to Title 5, Government Organization and Employees. ROLE OF SECONDARY STANDARDS Pub. L. 101–549, title VIII, § 817, Nov. 15, 1990, 104 Stat. 2697, provided that: ‘‘(a) REPORT.—The Administrator shall request the National Academy of Sciences to prepare a report to the Congress on the role of national secondary ambient air quality standards in protecting welfare and the environment. The report shall: ‘‘(1) include information on the effects on welfare and the environment which are caused by ambient concentrations of pollutants listed pursuant to section 108 [42 U.S.C. 7408] and other pollutants which may be listed; ‘‘(2) estimate welfare and environmental costs incurred as a result of such effects; ‘‘(3) examine the role of secondary standards and the State implementation planning process in preventing such effects; ‘‘(4) determine ambient concentrations of each such pollutant which would be adequate to protect welfare and the environment from such effects; ‘‘(5) estimate the costs and other impacts of meeting secondary standards; and ‘‘(6) consider other means consistent with the goals and objectives of the Clean Air Act [42 U.S.C. 7401 et (C) include a program to provide for the enforcement of the measures described in subparagraph (A), and regulation of the modification and construction of any stationary source within the areas covered by the plan as nec- Addendum – 005 CAA § 110 USCA Case #12-1100 § 7410 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE essary to assure that national ambient air quality standards are achieved, including a permit program as required in parts C and D of this subchapter; (D) contain adequate provisions— (i) prohibiting, consistent with the provisions of this subchapter, any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will— (I) contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any such national primary or secondary ambient air quality standard, or (II) interfere with measures required to be included in the applicable implementation plan for any other State under part C of this subchapter to prevent significant deterioration of air quality or to protect visibility, (ii) insuring compliance with the applicable requirements of sections 7426 and 7415 of this title (relating to interstate and international pollution abatement); (E) provide (i) necessary assurances that the State (or, except where the Administrator deems inappropriate, the general purpose local government or governments, or a regional agency designated by the State or general purpose local governments for such purpose) will have adequate personnel, funding, and authority under State (and, as appropriate, local) law to carry out such implementation plan (and is not prohibited by any provision of Federal or State law from carrying out such implementation plan or portion thereof), (ii) requirements that the State comply with the requirements respecting State boards under section 7428 of this title, and (iii) necessary assurances that, where the State has relied on a local or regional government, agency, or instrumentality for the implementation of any plan provision, the State has responsibility for ensuring adequate implementation of such plan provision; (F) require, as may be prescribed by the Administrator— (i) the installation, maintenance, and replacement of equipment, and the implementation of other necessary steps, by owners or operators of stationary sources to monitor emissions from such sources, (ii) periodic reports on the nature and amounts of emissions and emissions-related data from such sources, and (iii) correlation of such reports by the State agency with any emission limitations or standards established pursuant to this chapter, which reports shall be available at reasonable times for public inspection; (G) provide for authority comparable to that in section 7603 of this title and adequate contingency plans to implement such authority; (H) provide for revision of such plan— (i) from time to time as may be necessary to take account of revisions of such national primary or secondary ambient air quality standard or the availability of improved or more expeditious methods of attaining such standard, and Page 127 of 177 Page 6232 (ii) except as provided in paragraph (3)(C), whenever the Administrator finds on the basis of information available to the Administrator that the plan is substantially inadequate to attain the national ambient air quality standard which it implements or to otherwise comply with any additional requirements established under this chapter; (I) in the case of a plan or plan revision for an area designated as a nonattainment area, meet the applicable requirements of part D of this subchapter (relating to nonattainment areas); (J) meet the applicable requirements of section 7421 of this title (relating to consultation), section 7427 of this title (relating to public notification), and part C of this subchapter (relating to prevention of significant deterioration of air quality and visibility protection); (K) provide for— (i) the performance of such air quality modeling as the Administrator may prescribe for the purpose of predicting the effect on ambient air quality of any emissions of any air pollutant for which the Administrator has established a national ambient air quality standard, and (ii) the submission, upon request, of data related to such air quality modeling to the Administrator; (L) require the owner or operator of each major stationary source to pay to the permitting authority, as a condition of any permit required under this chapter, a fee sufficient to cover— (i) the reasonable costs of reviewing and acting upon any application for such a permit, and (ii) if the owner or operator receives a permit for such source, the reasonable costs of implementing and enforcing the terms and conditions of any such permit (not including any court costs or other costs associated with any enforcement action), until such fee requirement is superseded with respect to such sources by the Administrator’s approval of a fee program under subchapter V of this chapter; and (M) provide for consultation and participation by local political subdivisions affected by the plan. (3)(A) Repealed. Pub. L. 101–549, title I, § 101(d)(1), Nov. 15, 1990, 104 Stat. 2409. (B) As soon as practicable, the Administrator shall, consistent with the purposes of this chapter and the Energy Supply and Environmental Coordination Act of 1974 [15 U.S.C. 791 et seq.], review each State’s applicable implementation plans and report to the State on whether such plans can be revised in relation to fuel burning stationary sources (or persons supplying fuel to such sources) without interfering with the attainment and maintenance of any national ambient air quality standard within the period permitted in this section. If the Administrator determines that any such plan can be revised, he shall notify the State that a plan revision may be submitted by the State. Any plan revision which is submitted by the State shall, after pub- Addendum – 006 USCA Case #12-1100 Page 6239 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE Pub. L. 95–95, § 107(b), added subsec. (g) relating to Governor’s authority to issue temporary emergency suspensions. Subsec. (h). Pub. L. 95–190, § 14(a)(5), redesignated subsec. (g), added by Pub. L. 95–95, § 108(g), as (h). Former subsec. (h) redesignated (i). Subsec. (i). Pub. L. 95–190, § 14(a)(5), redesignated subsec. (h), added by Pub. L. 95–95, § 108(g), as (i). Former subsec. (i) redesignated (j) and amended. Subsec. (j). Pub. L. 95–190 § 14(a)(5), (6), redesignated subsec. (i), added by Pub. L. 95–95, § 108(g), as (j) and in subsec. (j) as so redesignated, substituted ‘‘will enable such source’’ for ‘‘at such source will enable it’’. 1974—Subsec. (a)(3). Pub. L. 93–319, § 4(a), designated existing provisions as subpar. (A) and added subpar. (B). Subsec. (c). Pub. L. 93–319, § 4(b), designated existing provisions as par. (1) and existing pars. (1), (2), and (3) as subpars. (A), (B), and (C), respectively, of such redesignated par. (1), and added par. (2). EFFECTIVE DATE OF 1977 AMENDMENT Amendment by Pub. L. 95–95 effective Aug. 7, 1977, except as otherwise expressly provided, see section 406(d) of Pub. L. 95–95, set out as a note under section 7401 of this title. PENDING ACTIONS AND PROCEEDINGS Suits, actions, and other proceedings lawfully commenced by or against the Administrator or any other officer or employee of the United States in his official capacity or in relation to the discharge of his official duties under act July 14, 1955, the Clean Air Act, as in effect immediately prior to the enactment of Pub. L. 95–95 [Aug. 7, 1977], not to abate by reason of the taking effect of Pub. L. 95–95, see section 406(a) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. MODIFICATION OR RESCISSION OF RULES, REGULATIONS, DETERMINATIONS, CONTRACTS, CERTIFIORDERS, CATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER ACTIONS All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect immediately prior to the date of enactment of Pub. L. 95–95 [Aug. 7, 1977] to continue in full force and effect until modified or rescinded in accordance with act July 14, 1955, as amended by Pub. L. 95–95 [this chapter], see section 406(b) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. MODIFICATION OR RESCISSION OF IMPLEMENTATION PLANS APPROVED AND IN EFFECT PRIOR TO AUG. 7, 1977 Nothing in the Clean Air Act Amendments of 1977 [Pub. L. 95–95] to affect any requirement of an approved implementation plan under this section or any other provision in effect under this chapter before Aug. 7, 1977, until modified or rescinded in accordance with this chapter as amended by the Clean Air Act Amendments of 1977, see section 406(c) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. SAVINGS PROVISION Section 16 of Pub. L. 91–604 provided that: ‘‘(a)(1) Any implementation plan adopted by any State and submitted to the Secretary of Health, Education, and Welfare, or to the Administrator pursuant to the Clean Air Act [this chapter] prior to enactment of this Act [Dec. 31, 1970] may be approved under section 110 of the Clean Air Act [this section] (as amended by this Act) [Pub. L. 91–604] and shall remain in effect, unless the Administrator determines that such implementation plan, or any portion thereof, is not consistent with applicable requirements of the Clean Air Act Page 128 of 177 § 7411 [this chapter] (as amended by this Act) and will not provide for the attainment of national primary ambient air quality standards in the time required by such Act. If the Administrator so determines, he shall, within 90 days after promulgation of any national ambient air quality standards pursuant to section 109(a) of the Clean Air Act [section 7409(a) of this title], notify the State and specify in what respects changes are needed to meet the additional requirements of such Act, including requirements to implement national secondary ambient air quality standards. If such changes are not adopted by the State after public hearings and within six months after such notification, the Administrator shall promulgate such changes pursuant to section 110(c) of such Act [subsec. (c) of this section]. ‘‘(2) The amendments made by section 4(b) [amending sections 7403 and 7415 of this title] shall not be construed as repealing or modifying the powers of the Administrator with respect to any conference convened under section 108(d) of the Clean Air Act [section 7415 of this title] before the date of enactment of this Act [Dec. 31, 1970]. ‘‘(b) Regulations or standards issued under this title II of the Clean Air Act [subchapter II of this chapter] prior to the enactment of this Act [Dec. 31, 1970] shall continue in effect until revised by the Administrator consistent with the purposes of such Act [this chapter].’’ FEDERAL ENERGY ADMINISTRATOR ‘‘Federal Energy Administrator’’, for purposes of this chapter, to mean Administrator of Federal Energy Administration established by Pub. L. 93–275, May 7, 1974, 88 Stat. 97, which is classified to section 761 et seq. of Title 15, Commerce and Trade, but with the term to mean any officer of the United States designated as such by the President until Federal Energy Administrator takes office and after Federal Energy Administration ceases to exist, see section 798 of Title 15, Commerce and Trade. Federal Energy Administration terminated and functions vested by law in Administrator thereof transferred to Secretary of Energy (unless otherwise specifically provided) by sections 7151(a) and 7293 of this title. § 7411. Standards of performance for new stationary sources (a) Definitions For purposes of this section: (1) The term ‘‘standard of performance’’ means a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. (2) The term ‘‘new source’’ means any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source. (3) The term ‘‘stationary source’’ means any building, structure, facility, or installation which emits or may emit any air pollutant. Nothing in subchapter II of this chapter relating to nonroad engines shall be construed to apply to stationary internal combustion engines. (4) The term ‘‘modification’’ means any physical change in, or change in the method of Addendum – 007 CAA § 111 USCA Case #12-1100 § 7411 Document #1401252 operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. (5) The term ‘‘owner or operator’’ means any person who owns, leases, operates, controls, or supervises a stationary source. (6) The term ‘‘existing source’’ means any stationary source other than a new source. (7) The term ‘‘technological system of continuous emission reduction’’ means— (A) a technological process for production or operation by any source which is inherently low-polluting or nonpolluting, or (B) a technological system for continuous reduction of the pollution generated by a source before such pollution is emitted into the ambient air, including precombustion cleaning or treatment of fuels. (8) A conversion to coal (A) by reason of an order under section 2(a) of the Energy Supply and Environmental Coordination Act of 1974 [15 U.S.C. 792(a)] or any amendment thereto, or any subsequent enactment which supersedes such Act [15 U.S.C. 791 et seq.], or (B) which qualifies under section 7413(d)(5)(A)(ii) 1 of this title, shall not be deemed to be a modification for purposes of paragraphs (2) and (4) of this subsection. (b) List of categories of stationary sources; standards of performance; information on pollution control techniques; sources owned or operated by United States; particular systems; revised standards (1)(A) The Administrator shall, within 90 days after December 31, 1970, publish (and from time to time thereafter shall revise) a list of categories of stationary sources. He shall include a category of sources in such list if in his judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. (B) Within one year after the inclusion of a category of stationary sources in a list under subparagraph (A), the Administrator shall publish proposed regulations, establishing Federal standards of performance for new sources within such category. The Administrator shall afford interested persons an opportunity for written comment on such proposed regulations. After considering such comments, he shall promulgate, within one year after such publication, such standards with such modifications as he deems appropriate. The Administrator shall, at least every 8 years, review and, if appropriate, revise such standards following the procedure required by this subsection for promulgation of such standards. Notwithstanding the requirements of the previous sentence, the Administrator need not review any such standard if the Administrator determines that such review is not appropriate in light of readily available information on the efficacy of such standard. Standards of performance or revisions thereof shall become effective upon promulgation. When implementation and enforcement of any requirement of this chapter indicate that emission lim1 See Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE References in Text note below. Page 129 of 177 Page 6240 itations and percent reductions beyond those required by the standards promulgated under this section are achieved in practice, the Administrator shall, when revising standards promulgated under this section, consider the emission limitations and percent reductions achieved in practice. (2) The Administrator may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standards. (3) The Administrator shall, from time to time, issue information on pollution control techniques for categories of new sources and air pollutants subject to the provisions of this section. (4) The provisions of this section shall apply to any new source owned or operated by the United States. (5) Except as otherwise authorized under subsection (h) of this section, nothing in this section shall be construed to require, or to authorize the Administrator to require, any new or modified source to install and operate any particular technological system of continuous emission reduction to comply with any new source standard of performance. (6) The revised standards of performance required by enactment of subsection (a)(1)(A)(i) and (ii) 1 of this section shall be promulgated not later than one year after August 7, 1977. Any new or modified fossil fuel fired stationary source which commences construction prior to the date of publication of the proposed revised standards shall not be required to comply with such revised standards. (c) State implementation and enforcement of standards of performance (1) Each State may develop and submit to the Administrator a procedure for implementing and enforcing standards of performance for new sources located in such State. If the Administrator finds the State procedure is adequate, he shall delegate to such State any authority he has under this chapter to implement and enforce such standards. (2) Nothing in this subsection shall prohibit the Administrator from enforcing any applicable standard of performance under this section. (d) Standards of performance for existing sources; remaining useful life of source (1) The Administrator shall prescribe regulations which shall establish a procedure similar to that provided by section 7410 of this title under which each State shall submit to the Administrator a plan which (A) establishes standards of performance for any existing source for any air pollutant (i) for which air quality criteria have not been issued or which is not included on a list published under section 7408(a) of this title or emitted from a source category which is regulated under section 7412 of this title but (ii) to which a standard of performance under this section would apply if such existing source were a new source, and (B) provides for the implementation and enforcement of such standards of performance. Regulations of the Administrator under this paragraph shall permit the State in applying a standard of performance to any particular source under a plan sub- Addendum – 008 USCA Case #12-1100 Page 6241 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE mitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies. (2) The Administrator shall have the same authority— (A) to prescribe a plan for a State in cases where the State fails to submit a satisfactory plan as he would have under section 7410(c) of this title in the case of failure to submit an implementation plan, and (B) to enforce the provisions of such plan in cases where the State fails to enforce them as he would have under sections 7413 and 7414 of this title with respect to an implementation plan. In promulgating a standard of performance under a plan prescribed under this paragraph, the Administrator shall take into consideration, among other factors, remaining useful lives of the sources in the category of sources to which such standard applies. (e) Prohibited acts After the effective date of standards of performance promulgated under this section, it shall be unlawful for any owner or operator of any new source to operate such source in violation of any standard of performance applicable to such source. (f) New source standards of performance (1) For those categories of major stationary sources that the Administrator listed under subsection (b)(1)(A) of this section before November 15, 1990, and for which regulations had not been proposed by the Administrator by November 15, 1990, the Administrator shall— (A) propose regulations establishing standards of performance for at least 25 percent of such categories of sources within 2 years after November 15, 1990; (B) propose regulations establishing standards of performance for at least 50 percent of such categories of sources within 4 years after November 15, 1990; and (C) propose regulations for the remaining categories of sources within 6 years after November 15, 1990. (2) In determining priorities for promulgating standards for categories of major stationary sources for the purpose of paragraph (1), the Administrator shall consider— (A) the quantity of air pollutant emissions which each such category will emit, or will be designed to emit; (B) the extent to which each such pollutant may reasonably be anticipated to endanger public health or welfare; and (C) the mobility and competitive nature of each such category of sources and the consequent need for nationally applicable new source standards of performance. (3) Before promulgating any regulations under this subsection or listing any category of major stationary sources as required under this subsection, the Administrator shall consult with appropriate representatives of the Governors and of State air pollution control agencies. (g) Revision of regulations (1) Upon application by the Governor of a State showing that the Administrator has failed Page 130 of 177 § 7411 to specify in regulations under subsection (f)(1) of this section any category of major stationary sources required to be specified under such regulations, the Administrator shall revise such regulations to specify any such category. (2) Upon application of the Governor of a State, showing that any category of stationary sources which is not included in the list under subsection (b)(1)(A) of this section contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare (notwithstanding that such category is not a category of major stationary sources), the Administrator shall revise such regulations to specify such category of stationary sources. (3) Upon application of the Governor of a State showing that the Administrator has failed to apply properly the criteria required to be considered under subsection (f)(2) of this section, the Administrator shall revise the list under subsection (b)(1)(A) of this section to apply properly such criteria. (4) Upon application of the Governor of a State showing that— (A) a new, innovative, or improved technology or process which achieves greater continuous emission reduction has been adequately demonstrated for any category of stationary sources, and (B) as a result of such technology or process, the new source standard of performance in effect under this section for such category no longer reflects the greatest degree of emission limitation achievable through application of the best technological system of continuous emission reduction which (taking into consideration the cost of achieving such emission reduction, and any non-air quality health and environmental impact and energy requirements) has been adequately demonstrated, the Administrator shall revise such standard of performance for such category accordingly. (5) Unless later deadlines for action of the Administrator are otherwise prescribed under this section, the Administrator shall, not later than three months following the date of receipt of any application by a Governor of a State, either— (A) find that such application does not contain the requisite showing and deny such application, or (B) grant such application and take the action required under this subsection. (6) Before taking any action required by subsection (f) of this section or by this subsection, the Administrator shall provide notice and opportunity for public hearing. (h) Design, equipment, work practice, or operational standard; alternative emission limitation (1) For purposes of this section, if in the judgment of the Administrator, it is not feasible to prescribe or enforce a standard of performance, he may instead promulgate a design, equipment, work practice, or operational standard, or combination thereof, which reflects the best technological system of continuous emission reduction which (taking into consideration the cost of achieving such emission reduction, and any non- Addendum – 009 USCA Case #12-1100 § 7411 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. In the event the Administrator promulgates a design or equipment standard under this subsection, he shall include as part of such standard such requirements as will assure the proper operation and maintenance of any such element of design or equipment. (2) For the purpose of this subsection, the phrase ‘‘not feasible to prescribe or enforce a standard of performance’’ means any situation in which the Administrator determines that (A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, or local law, or (B) the application of measurement methodology to a particular class of sources is not practicable due to technological or economic limitations. (3) If after notice and opportunity for public hearing, any person establishes to the satisfaction of the Administrator that an alternative means of emission limitation will achieve a reduction in emissions of any air pollutant at least equivalent to the reduction in emissions of such air pollutant achieved under the requirements of paragraph (1), the Administrator shall permit the use of such alternative by the source for purposes of compliance with this section with respect to such pollutant. (4) Any standard promulgated under paragraph (1) shall be promulgated in terms of standard of performance whenever it becomes feasible to promulgate and enforce such standard in such terms. (5) Any design, equipment, work practice, or operational standard, or any combination thereof, described in this subsection shall be treated as a standard of performance for purposes of the provisions of this chapter (other than the provisions of subsection (a) of this section and this subsection). (i) Country elevators Any regulations promulgated by the Administrator under this section applicable to grain elevators shall not apply to country elevators (as defined by the Administrator) which have a storage capacity of less than two million five hundred thousand bushels. (j) Innovative technological systems of continuous emission reduction (1)(A) Any person proposing to own or operate a new source may request the Administrator for one or more waivers from the requirements of this section for such source or any portion thereof with respect to any air pollutant to encourage the use of an innovative technological system or systems of continuous emission reduction. The Administrator may, with the consent of the Governor of the State in which the source is to be located, grant a waiver under this paragraph, if the Administrator determines after notice and opportunity for public hearing, that— (i) the proposed system or systems have not been adequately demonstrated, (ii) the proposed system or systems will operate effectively and there is a substantial Page 131 of 177 Page 6242 likelihood that such system or systems will achieve greater continuous emission reduction than that required to be achieved under the standards of performance which would otherwise apply, or achieve at least an equivalent reduction at lower cost in terms of energy, economic, or nonair quality environmental impact, (iii) the owner or operator of the proposed source has demonstrated to the satisfaction of the Administrator that the proposed system will not cause or contribute to an unreasonable risk to public health, welfare, or safety in its operation, function, or malfunction, and (iv) the granting of such waiver is consistent with the requirements of subparagraph (C). In making any determination under clause (ii), the Administrator shall take into account any previous failure of such system or systems to operate effectively or to meet any requirement of the new source performance standards. In determining whether an unreasonable risk exists under clause (iii), the Administrator shall consider, among other factors, whether and to what extent the use of the proposed technological system will cause, increase, reduce, or eliminate emissions of any unregulated pollutants; available methods for reducing or eliminating any risk to public health, welfare, or safety which may be associated with the use of such system; and the availability of other technological systems which may be used to conform to standards under this section without causing or contributing to such unreasonable risk. The Administrator may conduct such tests and may require the owner or operator of the proposed source to conduct such tests and provide such information as is necessary to carry out clause (iii) of this subparagraph. Such requirements shall include a requirement for prompt reporting of the emission of any unregulated pollutant from a system if such pollutant was not emitted, or was emitted in significantly lesser amounts without use of such system. (B) A waiver under this paragraph shall be granted on such terms and conditions as the Administrator determines to be necessary to assure— (i) emissions from the source will not prevent attainment and maintenance of any national ambient air quality standards, and (ii) proper functioning of the technological system or systems authorized. Any such term or condition shall be treated as a standard of performance for the purposes of subsection (e) of this section and section 7413 of this title. (C) The number of waivers granted under this paragraph with respect to a proposed technological system of continuous emission reduction shall not exceed such number as the Administrator finds necessary to ascertain whether or not such system will achieve the conditions specified in clauses (ii) and (iii) of subparagraph (A). (D) A waiver under this paragraph shall extend to the sooner of— (i) the date determined by the Administrator, after consultation with the owner or operator of the source, taking into consider- Addendum – 010 USCA Case #12-1100 Page 6243 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE Page 132 of 177 § 7411 ation the design, installation, and capital cost of the technological system or systems being used, or (ii) the date on which the Administrator determines that such system has failed to— (I) achieve at least an equivalent continuous emission reduction to that required to be achieved under the standards of performance which would otherwise apply, or (II) comply with the condition specified in paragraph (1)(A)(iii), § 701, Nov. 15, 1990, 104 Stat. 2672, and, as so amended, subsec. (d) of section 7413 no longer relates to final compliance orders. Subsection (a)(1) of this section, referred to in subsec. (b)(6), was amended generally by Pub. L. 101–549, title VII, § 403(a), Nov. 15, 1990, 104 Stat. 2631, and, as so amended, no longer contains subpars. and that such failure cannot be corrected. A prior section 111 of act July 14, 1955, was renumbered section 118 by Pub. L. 91–604 and is classified to section 7418 of this title. (E) In carrying out subparagraph (D)(i), the Administrator shall not permit any waiver for a source or portion thereof to extend beyond the date— (i) seven years after the date on which any waiver is granted to such source or portion thereof, or (ii) four years after the date on which such source or portion thereof commences operation, whichever is earlier. (F) No waiver under this subsection shall apply to any portion of a source other than the portion on which the innovative technological system or systems of continuous emission reduction is used. (2)(A) If a waiver under paragraph (1) is terminated under clause (ii) of paragraph (1)(D), the Administrator shall grant an extension of the requirements of this section for such source for such minimum period as may be necessary to comply with the applicable standard of performance under this section. Such period shall not extend beyond the date three years from the time such waiver is terminated. (B) An extension granted under this paragraph shall set forth emission limits and a compliance schedule containing increments of progress which require compliance with the applicable standards of performance as expeditiously as practicable and include such measures as are necessary and practicable in the interim to minimize emissions. Such schedule shall be treated as a standard of performance for purposes of subsection (e) of this section and section 7413 of this title. (July 14, 1955, ch. 360, title I, § 111, as added Pub. L. 91–604, § 4(a), Dec. 31, 1970, 84 Stat. 1683; amended Pub. L. 92–157, title III, § 302(f), Nov. 18, 1971, 85 Stat. 464; Pub. L. 95–95, title I, § 109(a)–(d)(1), (e), (f), title IV, § 401(b), Aug. 7, 1977, 91 Stat. 697–703, 791; Pub. L. 95–190, § 14(a)(7)–(9), Nov. 16, 1977, 91 Stat. 1399; Pub. L. 95–623, § 13(a), Nov. 9, 1978, 92 Stat. 3457; Pub. L. 101–549, title I, § 108(e)–(g), title III, § 302(a), (b), title IV, § 403(a), Nov. 15, 1990, 104 Stat. 2467, 2574, 2631.) REFERENCES IN TEXT Such Act, referred to in subsec. (a)(8), means Pub. L. 93–319, June 22, 1974, 88 Stat. 246, as amended, known as the Energy Supply and Environmental Coordination Act of 1974, which is classified principally to chapter 16C (§ 791 et seq.) of Title 15, Commerce and Trade. For complete classification of this Act to the Code, see Short Title note set out under section 791 of Title 15 and Tables. Section 7413 of this title, referred to in subsec. (a)(8), was amended generally by Pub. L. 101–549, title VII, CODIFICATION Section was formerly classified to section 1857c–6 of this title. PRIOR PROVISIONS AMENDMENTS 1990—Subsec. (a)(1). Pub. L. 101–549, § 403(a), amended par. (1) generally, substituting provisions defining ‘‘standard of performance’’ with respect to any air pollutant for provisions defining such term with respect to subsec. (b) fossil fuel fired and other stationary sources and subsec. (d) particular sources. Subsec. (a)(3). Pub. L. 101–549, § 108(f), inserted at end ‘‘Nothing in subchapter II of this chapter relating to nonroad engines shall be construed to apply to stationary internal combustion engines.’’ Subsec. (b)(1)(B). Pub. L. 101–549, § 108(e)(1), substituted ‘‘Within one year’’ for ‘‘Within 120 days’’, ‘‘within one year’’ for ‘‘within 90 days’’, and ‘‘every 8 years’’ for ‘‘every four years’’, inserted before last sentence ‘‘Notwithstanding the requirements of the previous sentence, the Administrator need not review any such standard if the Administrator determines that such review is not appropriate in light of readily available information on the efficacy of such standard.’’, and inserted at end ‘‘When implementation and enforcement of any requirement of this chapter indicate that emission limitations and percent reductions beyond those required by the standards promulgated under this section are achieved in practice, the Administrator shall, when revising standards promulgated under this section, consider the emission limitations and percent reductions achieved in practice.’’ Subsec. (d)(1)(A)(i). Pub. L. 101–549, § 302(a), which directed the substitution of ‘‘7412(b)’’ for ‘‘7412(b)(1)(A)’’, could not be executed, because of the prior amendment by Pub. L. 101–549, § 108(g), see below. Pub. L. 101–549, § 108(g), substituted ‘‘or emitted from a source category which is regulated under section 7412 of this title’’ for ‘‘or 7412(b)(1)(A)’’. Subsec. (f)(1). Pub. L. 101–549, § 108(e)(2), amended par. (1) generally, substituting present provisions for provisions requiring the Administrator to promulgate regulations listing the categories of major stationary sources not on the required list by Aug. 7, 1977, and regulations establishing standards of performance for such categories. Subsec. (g)(5) to (8). Pub. L. 101–549, § 302(b), redesignated par. (7) as (5) and struck out ‘‘or section 7412 of this title’’ after ‘‘this section’’, redesignated par. (8) as (6), and struck out former pars. (5) and (6) which read as follows: ‘‘(5) Upon application by the Governor of a State showing that the Administrator has failed to list any air pollutant which causes, or contributes to, air pollution which may reasonably be anticipated to result in an increase in mortality or an increase in serious irreversible, or incapacitating reversible, illness as a hazardous air pollutant under section 7412 of this title the Administrator shall revise the list of hazardous air pollutants under such section to include such pollutant. ‘‘(6) Upon application by the Governor of a State showing that any category of stationary sources of a hazardous air pollutant listed under section 7412 of this title is not subject to emission standards under such section, the Administrator shall propose and promulgate such emission standards applicable to such category of sources.’’ Addendum – 011 USCA Case #12-1100 § 7412 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE 1978—Subsecs. (d)(1)(A)(ii), (g)(4)(B). Pub. L. 95–623, § 13(a)(2), substituted ‘‘under this section’’ for ‘‘under subsection (b) of this section’’. Subsec. (h)(5). Pub. L. 95–623, § 13(a)(1), added par. (5). Subsec. (j). Pub. L. 95–623, § 13(a)(3), substituted in pars. (1)(A) and (2)(A) ‘‘standards under this section’’ and ‘‘under this section’’ for ‘‘standards under subsection (b) of this section’’ and ‘‘under subsection (b) of this section’’, respectively. 1977—Subsec. (a)(1). Pub. L. 95–95, § 109(c)(1)(A), added subpars. (A), (B), and (C), substituted ‘‘For the purpose of subparagraphs (A)(i) and (ii) and (B), a standard of performance shall reflect’’ for ‘‘a standard for emissions of air pollutants which reflects’’, ‘‘and the percentage reduction achievable’’ for ‘‘achievable’’, and ‘‘technological system of continuous emission reduction which (taking into consideration the cost of achieving such emission reduction, and any nonair quality health and environment impact and energy requirements)’’ for ‘‘system of emission reduction which (taking into account the cost of achieving such reduction)’’ in existing provisions, and inserted provision that, for the purpose of subparagraph (1)(A)(ii), any cleaning of the fuel or reduction in the pollution characteristics of the fuel after extraction and prior to combustion may be credited, as determined under regulations promulgated by the Administrator, to a source which burns such fuel. Subsec. (a)(7). Pub. L. 95–95, § 109(c)(1)(B), added par. (7) defining ‘‘technological system of continuous emission reduction’’. Pub. L. 95–95, § 109(f), added par. (7) directing that under certain circumstances a conversion to coal not be deemed a modification for purposes of pars. (2) and (4). Subsec. (a)(7), (8). Pub. L. 95–190, § 14(a)(7), redesignated second par. (7) as (8). Subsec. (b)(1)(A). Pub. L. 95–95, § 401(b), substituted ‘‘such list if in his judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger’’ for ‘‘such list if he determines it may contribute significantly to air pollution which causes or contributes to the endangerment of’’. Subsec. (b)(1)(B). Pub. L. 95–95, § 109(c)(2), substituted ‘‘shall, at least every four years, review and, if appropriate,’’ for ‘‘may, from time to time,’’. Subsec. (b)(5), (6). Pub. L. 95–95, § 109(c)(3), added pars. (5) and (6). Subsec. (c)(1). Pub. L. 95–95, § 109(d)(1), struck out ‘‘(except with respect to new sources owned or operated by the United States)’’ after ‘‘implement and enforce such standards’’. Subsec. (d)(1). Pub. L. 95–95, § 109(b)(1), substituted ‘‘standards of performance’’ for ‘‘emission standards’’ and inserted provisions directing that regulations of the Administrator permit the State, in applying a standard of performance to any particular source under a submitted plan, to take into consideration, among other factors, the remaining useful life of the existing source to which the standard applies. Subsec. (d)(2). Pub. L. 95–95, § 109(b)(2), provided that, in promulgating a standard of performance under a plan, the Administrator take into consideration, among other factors, the remaining useful lives of the sources in the category of sources to which the standard applies. Subsecs. (f) to (i). Pub. L. 95–95, § 109(a), added subsecs. (f) to (i). Subsecs. (j), (k). Pub. L. 95–190, § 14(a)(8), (9), redesignated subsec. (k) as (j) and, as so redesignated, substituted ‘‘(B)’’ for ‘‘(8)’’ as designation for second subpar. in par. (2). Former subsec. (j), added by Pub. L. 95–95, § 109(e), which related to compliance with applicable standards of performance, was struck out. Pub. L. 95–95, § 109(e), added subsec. (k). 1971—Subsec. (b)(1)(B). Pub. L. 92–157 substituted in first sentence ‘‘publish proposed’’ for ‘‘propose’’. EFFECTIVE DATE OF 1977 AMENDMENT Amendment by Pub. L. 95–95 effective Aug. 7, 1977, except as otherwise expressly provided, see section 406(d) Page 133 of 177 Page 6244 of Pub. L. 95–95, set out as a note under section 7401 of this title. REGULATIONS Section 403(b), (c) of Pub. L. 101–549 provided that: ‘‘(b) REVISED REGULATIONS.—Not later than three years after the date of enactment of the Clean Air Act Amendments of 1990 [Nov. 15, 1990], the Administrator shall promulgate revised regulations for standards of performance for new fossil fuel fired electric utility units commencing construction after the date on which such regulations are proposed that, at a minimum, require any source subject to such revised standards to emit sulfur dioxide at a rate not greater than would have resulted from compliance by such source with the applicable standards of performance under this section [amending sections 7411 and 7479 of this title] prior to such revision. ‘‘(c) APPLICABILITY.—The provisions of subsections (a) [amending this section] and (b) apply only so long as the provisions of section 403(e) of the Clean Air Act [42 U.S.C. 7651b(e)] remain in effect.’’ TRANSFER OF FUNCTIONS Enforcement functions of Administrator or other official in Environmental Protection Agency related to compliance with new source performance standards under this section with respect to pre-construction, construction, and initial operation of transportation system for Canadian and Alaskan natural gas transferred to Federal Inspector, Office of Federal Inspector for the Alaska Natural Gas Transportation System, until first anniversary of date of initial operation of Alaska Natural Gas Transportation System, see Reorg. Plan No. 1 of 1979, eff. July 1, 1979, §§ 102(a), 203(a), 44 F.R. 33663, 33666, 93 Stat. 1373, 1376, set out in the Appendix to Title 5, Government Organization and Employees. Office of Federal Inspector for the Alaska Natural Gas Transportation System abolished and functions and authority vested in Inspector transferred to Secretary of Energy by section 3012(b) of Pub. L. 102–486, set out as an Abolition of Office of Federal Inspector note under section 719e of Title 15, Commerce and Trade. Functions and authority vested in Secretary of Energy subsequently transferred to Federal Coordinator for Alaska Natural Gas Transportation Projects by section 720d(f) of Title 15. PENDING ACTIONS AND PROCEEDINGS Suits, actions, and other proceedings lawfully commenced by or against the Administrator or any other officer or employee of the United States in his official capacity or in relation to the discharge of his official duties under act July 14, 1955, the Clean Air Act, as in effect immediately prior to the enactment of Pub. L. 95–95 [Aug. 7, 1977], not to abate by reason of the taking effect of Pub. L. 95–95, see section 406(a) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. MODIFICATION OR RESCISSION OF RULES, REGULATIONS, DETERMINATIONS, CONTRACTS, CERTIFIORDERS, CATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER ACTIONS All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect immediately prior to the date of enactment of Pub. L. 95–95 [Aug. 7, 1977] to continue in full force and effect until modified or rescinded in accordance with act July 14, 1955, as amended by Pub. L. 95–95 [this chapter], see section 406(b) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. § 7412. Hazardous air pollutants (a) Definitions For purposes of this section, except subsection (r) of this section— Addendum – 012 CAA § 112 USCA Case #12-1100 Page 6245 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE (1) Major source The term ‘‘major source’’ means any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit considering controls, in the aggregate, 10 tons per year or more of any hazardous air pollutant or 25 tons per year or more of any combination of hazardous air pollutants. The Administrator may establish a lesser quantity, or in the case of radionuclides different criteria, for a major source than that specified in the previous sentence, on the basis of the potency of the air pollutant, persistence, potential for bioaccumulation, other characteristics of the air pollutant, or other relevant factors. (2) Area source The term ‘‘area source’’ means any stationary source of hazardous air pollutants that is not a major source. For purposes of this section, the term ‘‘area source’’ shall not include motor vehicles or nonroad vehicles subject to regulation under subchapter II of this chapter. (3) Stationary source The term ‘‘stationary source’’ shall have the same meaning as such term has under section 7411(a) of this title. (4) New source The term ‘‘new source’’ means a stationary source the construction or reconstruction of which is commenced after the Administrator first proposes regulations under this section establishing an emission standard applicable to such source. (5) Modification The term ‘‘modification’’ means any physical change in, or change in the method of operation of, a major source which increases the actual emissions of any hazardous air pollutant emitted by such source by more than a de minimis amount or which results in the emission of any hazardous air pollutant not previously emitted by more than a de minimis amount. (6) Hazardous air pollutant The term ‘‘hazardous air pollutant’’ means any air pollutant listed pursuant to subsection (b) of this section. (7) Adverse environmental effect The term ‘‘adverse environmental effect’’ means any significant and widespread adverse effect, which may reasonably be anticipated, to wildlife, aquatic life, or other natural resources, including adverse impacts on populations of endangered or threatened species or significant degradation of environmental quality over broad areas. (8) Electric utility steam generating unit The term ‘‘electric utility steam generating unit’’ means any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 Page 134 of 177 § 7412 megawatts electrical output to any utility power distribution system for sale shall be considered an electric utility steam generating unit. (9) Owner or operator The term ‘‘owner or operator’’ means any person who owns, leases, operates, controls, or supervises a stationary source. (10) Existing source The term ‘‘existing source’’ means any stationary source other than a new source. (11) Carcinogenic effect Unless revised, the term ‘‘carcinogenic effect’’ shall have the meaning provided by the Administrator under Guidelines for Carcinogenic Risk Assessment as of the date of enactment.1 Any revisions in the existing Guidelines shall be subject to notice and opportunity for comment. (b) List of pollutants (1) Initial list The Congress establishes for purposes of this section a list of hazardous air pollutants as follows: CAS number 75070 60355 75058 98862 53963 107028 79061 79107 107131 107051 92671 62533 90040 1332214 71432 92875 98077 100447 92524 117817 542881 75252 106990 156627 105602 133062 63252 75150 56235 463581 120809 133904 57749 7782505 79118 532274 108907 510156 67663 107302 126998 1319773 95487 1 See Chemical name Acetaldehyde Acetamide Acetonitrile Acetophenone 2-Acetylaminofluorene Acrolein Acrylamide Acrylic acid Acrylonitrile Allyl chloride 4-Aminobiphenyl Aniline o-Anisidine Asbestos Benzene (including benzene from gasoline) Benzidine Benzotrichloride Benzyl chloride Biphenyl Bis(2-ethylhexyl)phthalate (DEHP) Bis(chloromethyl)ether Bromoform 1,3-Butadiene Calcium cyanamide Caprolactam Captan Carbaryl Carbon disulfide Carbon tetrachloride Carbonyl sulfide Catechol Chloramben Chlordane Chlorine Chloroacetic acid 2-Chloroacetophenone Chlorobenzene Chlorobenzilate Chloroform Chloromethyl methyl ether Chloroprene Cresols/Cresylic acid (isomers and mixture) o-Cresol References in Text note below. Addendum – 013 USCA Case #12-1100 § 7412 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE CAS number Chemical name CAS number 108394 106445 98828 94757 3547044 334883 132649 96128 84742 106467 91941 111444 542756 62737 111422 121697 64675 119904 60117 119937 79447 68122 57147 131113 77781 534521 51285 121142 123911 122667 106898 106887 140885 100414 51796 75003 106934 107062 107211 151564 75218 96457 75343 50000 76448 118741 87683 77474 67721 822060 680319 110543 302012 7647010 7664393 123319 78591 58899 108316 67561 72435 74839 74873 71556 78933 60344 74884 108101 624839 80626 1634044 101144 75092 101688 101779 91203 98953 m-Cresol p-Cresol Cumene 2,4-D, salts and esters DDE Diazomethane Dibenzofurans 1,2-Dibromo-3-chloropropane Dibutylphthalate 1,4-Dichlorobenzene(p) 3,3-Dichlorobenzidene Dichloroethyl ether (Bis(2-chloroethyl)ether) 1,3-Dichloropropene Dichlorvos Diethanolamine N,N-Diethyl aniline (N,N-Dimethylaniline) Diethyl sulfate 3,3-Dimethoxybenzidine Dimethyl aminoazobenzene 3,3′-Dimethyl benzidine Dimethyl carbamoyl chloride Dimethyl formamide 1,1-Dimethyl hydrazine Dimethyl phthalate Dimethyl sulfate 4,6-Dinitro-o-cresol, and salts 2,4-Dinitrophenol 2,4-Dinitrotoluene 1,4-Dioxane (1,4-Diethyleneoxide) 1,2-Diphenylhydrazine Epichlorohydrin (l-Chloro-2,3-epoxypropane) 1,2-Epoxybutane Ethyl acrylate Ethyl benzene Ethyl carbamate (Urethane) Ethyl chloride (Chloroethane) Ethylene dibromide (Dibromoethane) Ethylene dichloride (1,2-Dichloroethane) Ethylene glycol Ethylene imine (Aziridine) Ethylene oxide Ethylene thiourea Ethylidene dichloride (1,1-Dichloroethane) Formaldehyde Heptachlor Hexachlorobenzene Hexachlorobutadiene Hexachlorocyclopentadiene Hexachloroethane Hexamethylene-1,6-diisocyanate Hexamethylphosphoramide Hexane Hydrazine Hydrochloric acid Hydrogen fluoride (Hydrofluoric acid) Hydroquinone Isophorone Lindane (all isomers) Maleic anhydride Methanol Methoxychlor Methyl bromide (Bromomethane) Methyl chloride (Chloromethane) Methyl chloroform (1,1,1-Trichloroethane) Methyl ethyl ketone (2-Butanone) Methyl hydrazine Methyl iodide (Iodomethane) Methyl isobutyl ketone (Hexone) Methyl isocyanate Methyl methacrylate Methyl tert butyl ether 4,4-Methylene bis(2-chloroaniline) Methylene chloride (Dichloromethane) Methylene diphenyl diisocyanate (MDI) 4,4′-Methylenedianiline Naphthalene Nitrobenzene 92933 100027 79469 684935 62759 59892 56382 82688 87865 108952 106503 75445 7803512 7723140 85449 1336363 1120714 57578 123386 114261 78875 75569 75558 91225 106514 100425 96093 1746016 79345 127184 7550450 108883 95807 584849 95534 8001352 120821 79005 79016 95954 88062 121448 1582098 540841 108054 593602 75014 75354 1330207 95476 108383 106423 0 0 Page 135 of 177 Page 6246 Chemical name 4-Nitrobiphenyl 4-Nitrophenol 2-Nitropropane N-Nitroso-N-methylurea N-Nitrosodimethylamine N-Nitrosomorpholine Parathion Pentachloronitrobenzene (Quintobenzene) Pentachlorophenol Phenol p-Phenylenediamine Phosgene Phosphine Phosphorus Phthalic anhydride Polychlorinated biphenyls (Aroclors) 1,3-Propane sultone beta-Propiolactone Propionaldehyde Propoxur (Baygon) Propylene dichloride (1,2-Dichloropropane) Propylene oxide 1,2-Propylenimine (2-Methyl aziridine) Quinoline Quinone Styrene Styrene oxide 2,3,7,8-Tetrachlorodibenzo-p-dioxin 1,1,2,2-Tetrachloroethane Tetrachloroethylene (Perchloroethylene) Titanium tetrachloride Toluene 2,4-Toluene diamine 2,4-Toluene diisocyanate o-Toluidine Toxaphene (chlorinated camphene) 1,2,4-Trichlorobenzene 1,1,2-Trichloroethane Trichloroethylene 2,4,5-Trichlorophenol 2,4,6-Trichlorophenol Triethylamine Trifluralin 2,2,4-Trimethylpentane Vinyl acetate Vinyl bromide Vinyl chloride Vinylidene chloride (1,1-Dichloroethylene) Xylenes (isomers and mixture) o-Xylenes m-Xylenes p-Xylenes Antimony Compounds Arsenic Compounds (inorganic including arsine) 0 Beryllium Compounds 0 Cadmium Compounds 0 Chromium Compounds 0 Cobalt Compounds 0 Coke Oven Emissions 0 Cyanide Compounds 1 0 Glycol ethers 2 0 Lead Compounds 0 Manganese Compounds 0 Mercury Compounds 0 Fine mineral fibers 3 0 Nickel Compounds 0 Polycylic Organic Matter 4 0 Radionuclides (including radon) 5 0 Selenium Compounds NOTE: For all listings above which contain the word ‘‘compounds’’ and for glycol ethers, the following applies: Unless otherwise specified, these listings are defined as including any unique chemical substance that contains the named chemical (i.e., antimony, arsenic, etc.) as part of that chemical’s infrastructure. Addendum – 014 USCA Case #12-1100 Page 6247 Document #1401252 1 X′CN where X = H′ or any other group where a formal dissociation may occur. For example KCN or Ca(CN)2. 2 Includes mono- and di- ethers of ethylene glycol, diethylene glycol, and triethylene glycol R–(OCH2CH2)n–OR′ where n = 1, 2, or 3 R = alkyl or aryl groups R′ = R, H, or groups which, when removed, yield glycol ethers with the structure: R–(OCH2CH)n–OH. Polymers are excluded from the glycol category. 3 Includes mineral fiber emissions from facilities manufacturing or processing glass, rock, or slag fibers (or other mineral derived fibers) of average diameter 1 micrometer or less. 4 Includes organic compounds with more than one benzene ring, and which have a boiling point greater than or equal to 100°C. 5 A type of atom which spontaneously undergoes radioactive decay. (2) Revision of the list The Administrator shall periodically review the list established by this subsection and publish the results thereof and, where appropriate, revise such list by rule, adding pollutants which present, or may present, through inhalation or other routes of exposure, a threat of adverse human health effects (including, but not limited to, substances which are known to be, or may reasonably be anticipated to be, carcinogenic, mutagenic, teratogenic, neurotoxic, which cause reproductive dysfunction, or which are acutely or chronically toxic) or adverse environmental effects whether through ambient concentrations, bioaccumulation, deposition, or otherwise, but not including releases subject to regulation under subsection (r) of this section as a result of emissions to the air. No air pollutant which is listed under section 7408(a) of this title may be added to the list under this section, except that the prohibition of this sentence shall not apply to any pollutant which independently meets the listing criteria of this paragraph and is a precursor to a pollutant which is listed under section 7408(a) of this title or to any pollutant which is in a class of pollutants listed under such section. No substance, practice, process or activity regulated under subchapter VI of this chapter shall be subject to regulation under this section solely due to its adverse effects on the environment. (3) Petitions to modify the list (A) Beginning at any time after 6 months after November 15, 1990, any person may petition the Administrator to modify the list of hazardous air pollutants under this subsection by adding or deleting a substance or, in case of listed pollutants without CAS numbers (other than coke oven emissions, mineral fibers, or polycyclic organic matter) removing certain unique substances. Within 18 months after receipt of a petition, the Administrator shall either grant or deny the petition by publishing a written explanation of the reasons for the Administrator’s decision. Any such petition shall include a showing by the petitioner that there is adequate data on the health or environmental defects 2 of the pollutant or other evidence adequate to support the petition. The Administrator may not deny a petition solely 2 So Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE in original. Probably should be ‘‘effects’’. Page 136 of 177 § 7412 on the basis of inadequate resources or time for review. (B) The Administrator shall add a substance to the list upon a showing by the petitioner or on the Administrator’s own determination that the substance is an air pollutant and that emissions, ambient concentrations, bioaccumulation or deposition of the substance are known to cause or may reasonably be anticipated to cause adverse effects to human health or adverse environmental effects. (C) The Administrator shall delete a substance from the list upon a showing by the petitioner or on the Administrator’s own determination that there is adequate data on the health and environmental effects of the substance to determine that emissions, ambient concentrations, bioaccumulation or deposition of the substance may not reasonably be anticipated to cause any adverse effects to the human health or adverse environmental effects. (D) The Administrator shall delete one or more unique chemical substances that contain a listed hazardous air pollutant not having a CAS number (other than coke oven emissions, mineral fibers, or polycyclic organic matter) upon a showing by the petitioner or on the Administrator’s own determination that such unique chemical substances that contain the named chemical of such listed hazardous air pollutant meet the deletion requirements of subparagraph (C). The Administrator must grant or deny a deletion petition prior to promulgating any emission standards pursuant to subsection (d) of this section applicable to any source category or subcategory of a listed hazardous air pollutant without a CAS number listed under subsection (b) of this section for which a deletion petition has been filed within 12 months of November 15, 1990. (4) Further information If the Administrator determines that information on the health or environmental effects of a substance is not sufficient to make a determination required by this subsection, the Administrator may use any authority available to the Administrator to acquire such information. (5) Test methods The Administrator may establish, by rule, test measures and other analytic procedures for monitoring and measuring emissions, ambient concentrations, deposition, and bioaccumulation of hazardous air pollutants. (6) Prevention of significant deterioration The provisions of part C of this subchapter (prevention of significant deterioration) shall not apply to pollutants listed under this section. (7) Lead The Administrator may not list elemental lead as a hazardous air pollutant under this subsection. (c) List of source categories (1) In general Not later than 12 months after November 15, 1990, the Administrator shall publish, and Addendum – 015 USCA Case #12-1100 § 7412 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE shall from time to time, but no less often than every 8 years, revise, if appropriate, in response to public comment or new information, a list of all categories and subcategories of major sources and area sources (listed under paragraph (3)) of the air pollutants listed pursuant to subsection (b) of this section. To the extent practicable, the categories and subcategories listed under this subsection shall be consistent with the list of source categories established pursuant to section 7411 of this title and part C of this subchapter. Nothing in the preceding sentence limits the Administrator’s authority to establish subcategories under this section, as appropriate. (2) Requirement for emissions standards For the categories and subcategories the Administrator lists, the Administrator shall establish emissions standards under subsection (d) of this section, according to the schedule in this subsection and subsection (e) of this section. (3) Area sources The Administrator shall list under this subsection each category or subcategory of area sources which the Administrator finds presents a threat of adverse effects to human health or the environment (by such sources individually or in the aggregate) warranting regulation under this section. The Administrator shall, not later than 5 years after November 15, 1990, and pursuant to subsection (k)(3)(B) of this section, list, based on actual or estimated aggregate emissions of a listed pollutant or pollutants, sufficient categories or subcategories of area sources to ensure that area sources representing 90 percent of the area source emissions of the 30 hazardous air pollutants that present the greatest threat to public health in the largest number of urban areas are subject to regulation under this section. Such regulations shall be promulgated not later than 10 years after November 15, 1990. (4) Previously regulated categories The Administrator may, in the Administrator’s discretion, list any category or subcategory of sources previously regulated under this section as in effect before November 15, 1990. (5) Additional categories In addition to those categories and subcategories of sources listed for regulation pursuant to paragraphs (1) and (3), the Administrator may at any time list additional categories and subcategories of sources of hazardous air pollutants according to the same criteria for listing applicable under such paragraphs. In the case of source categories and subcategories listed after publication of the initial list required under paragraph (1) or (3), emission standards under subsection (d) of this section for the category or subcategory shall be promulgated within 10 years after November 15, 1990, or within 2 years after the date on which such category or subcategory is listed, whichever is later. (6) Specific pollutants With respect to alkylated lead compounds, polycyclic organic matter, hexachlorobenzene, Page 137 of 177 Page 6248 mercury, polychlorinated biphenyls, 2,3,7,8tetrachlorodibenzofurans and 2,3,7,8-tetrachlorodibenzo-p-dioxin, the Administrator shall, not later than 5 years after November 15, 1990, list categories and subcategories of sources assuring that sources accounting for not less than 90 per centum of the aggregate emissions of each such pollutant are subject to standards under subsection (d)(2) or (d)(4) of this section. Such standards shall be promulgated not later than 10 years after November 15, 1990. This paragraph shall not be construed to require the Administrator to promulgate standards for such pollutants emitted by electric utility steam generating units. (7) Research facilities The Administrator shall establish a separate category covering research or laboratory facilities, as necessary to assure the equitable treatment of such facilities. For purposes of this section, ‘‘research or laboratory facility’’ means any stationary source whose primary purpose is to conduct research and development into new processes and products, where such source is operated under the close supervision of technically trained personnel and is not engaged in the manufacture of products for commercial sale in commerce, except in a de minimis manner. (8) Boat manufacturing When establishing emissions standards for styrene, the Administrator shall list boat manufacturing as a separate subcategory unless the Administrator finds that such listing would be inconsistent with the goals and requirements of this chapter. (9) Deletions from the list (A) Where the sole reason for the inclusion of a source category on the list required under this subsection is the emission of a unique chemical substance, the Administrator shall delete the source category from the list if it is appropriate because of action taken under either subparagraphs (C) or (D) of subsection (b)(3) of this section. (B) The Administrator may delete any source category from the list under this subsection, on petition of any person or on the Administrator’s own motion, whenever the Administrator makes the following determination or determinations, as applicable: (i) In the case of hazardous air pollutants emitted by sources in the category that may result in cancer in humans, a determination that no source in the category (or group of sources in the case of area sources) emits such hazardous air pollutants in quantities which may cause a lifetime risk of cancer greater than one in one million to the individual in the population who is most exposed to emissions of such pollutants from the source (or group of sources in the case of area sources). (ii) In the case of hazardous air pollutants that may result in adverse health effects in humans other than cancer or adverse environmental effects, a determination that emissions from no source in the category or subcategory concerned (or group of sources Addendum – 016 USCA Case #12-1100 Page 6249 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE in the case of area sources) exceed a level which is adequate to protect public health with an ample margin of safety and no adverse environmental effect will result from emissions from any source (or from a group of sources in the case of area sources). The Administrator shall grant or deny a petition under this paragraph within 1 year after the petition is filed. (d) Emission standards (1) In general The Administrator shall promulgate regulations establishing emission standards for each category or subcategory of major sources and area sources of hazardous air pollutants listed for regulation pursuant to subsection (c) of this section in accordance with the schedules provided in subsections (c) and (e) of this section. The Administrator may distinguish among classes, types, and sizes of sources within a category or subcategory in establishing such standards except that, there shall be no delay in the compliance date for any standard applicable to any source under subsection (i) of this section as the result of the authority provided by this sentence. (2) Standards and methods Emissions standards promulgated under this subsection and applicable to new or existing sources of hazardous air pollutants shall require the maximum degree of reduction in emissions of the hazardous air pollutants subject to this section (including a prohibition on such emissions, where achievable) that the Administrator, taking into consideration the cost of achieving such emission reduction, and any non-air quality health and environmental impacts and energy requirements, determines is achievable for new or existing sources in the category or subcategory to which such emission standard applies, through application of measures, processes, methods, systems or techniques including, but not limited to, measures which— (A) reduce the volume of, or eliminate emissions of, such pollutants through process changes, substitution of materials or other modifications, (B) enclose systems or processes to eliminate emissions, (C) collect, capture or treat such pollutants when released from a process, stack, storage or fugitive emissions point, (D) are design, equipment, work practice, or operational standards (including requirements for operator training or certification) as provided in subsection (h) of this section, or (E) are a combination of the above. None of the measures described in subparagraphs (A) through (D) shall, consistent with the provisions of section 7414(c) of this title, in any way compromise any United States patent or United States trademark right, or any confidential business information, or any trade secret or any other intellectual property right. (3) New and existing sources The maximum degree of reduction in emissions that is deemed achievable for new Page 138 of 177 § 7412 sources in a category or subcategory shall not be less stringent than the emission control that is achieved in practice by the best controlled similar source, as determined by the Administrator. Emission standards promulgated under this subsection for existing sources in a category or subcategory may be less stringent than standards for new sources in the same category or subcategory but shall not be less stringent, and may be more stringent than— (A) the average emission limitation achieved by the best performing 12 percent of the existing sources (for which the Administrator has emissions information), excluding those sources that have, within 18 months before the emission standard is proposed or within 30 months before such standard is promulgated, whichever is later, first achieved a level of emission rate or emission reduction which complies, or would comply if the source is not subject to such standard, with the lowest achievable emission rate (as defined by section 7501 of this title) applicable to the source category and prevailing at the time, in the category or subcategory for categories and subcategories with 30 or more sources, or (B) the average emission limitation achieved by the best performing 5 sources (for which the Administrator has or could reasonably obtain emissions information) in the category or subcategory for categories or subcategories with fewer than 30 sources. (4) Health threshold With respect to pollutants for which a health threshold has been established, the Administrator may consider such threshold level, with an ample margin of safety, when establishing emission standards under this subsection. (5) Alternative standard for area sources With respect only to categories and subcategories of area sources listed pursuant to subsection (c) of this section, the Administrator may, in lieu of the authorities provided in paragraph (2) and subsection (f) of this section, elect to promulgate standards or requirements applicable to sources in such categories or subcategories which provide for the use of generally available control technologies or management practices by such sources to reduce emissions of hazardous air pollutants. (6) Review and revision The Administrator shall review, and revise as necessary (taking into account developments in practices, processes, and control technologies), emission standards promulgated under this section no less often than every 8 years. (7) Other requirements preserved No emission standard or other requirement promulgated under this section shall be interpreted, construed or applied to diminish or replace the requirements of a more stringent emission limitation or other applicable requirement established pursuant to section 7411 of this title, part C or D of this subchapter, or Addendum – 017 USCA Case #12-1100 § 7412 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE other authority of this chapter or a standard issued under State authority. (8) Coke ovens (A) Not later than December 31, 1992, the Administrator shall promulgate regulations establishing emission standards under paragraphs (2) and (3) of this subsection for coke oven batteries. In establishing such standards, the Administrator shall evaluate— (i) the use of sodium silicate (or equivalent) luting compounds to prevent door leaks, and other operating practices and technologies for their effectiveness in reducing coke oven emissions, and their suitability for use on new and existing coke oven batteries, taking into account costs and reasonable commercial door warranties; and (ii) as a basis for emission standards under this subsection for new coke oven batteries that begin construction after the date of proposal of such standards, the Jewell design Thompson non-recovery coke oven batteries and other non-recovery coke oven technologies, and other appropriate emission control and coke production technologies, as to their effectiveness in reducing coke oven emissions and their capability for production of steel quality coke. Such regulations shall require at a minimum that coke oven batteries will not exceed 8 per centum leaking doors, 1 per centum leaking lids, 5 per centum leaking offtakes, and 16 seconds visible emissions per charge, with no exclusion for emissions during the period after the closing of self-sealing oven doors. Notwithstanding subsection (i) of this section, the compliance date for such emission standards for existing coke oven batteries shall be December 31, 1995. (B) The Administrator shall promulgate work practice regulations under this subsection for coke oven batteries requiring, as appropriate— (i) the use of sodium silicate (or equivalent) luting compounds, if the Administrator determines that use of sodium silicate is an effective means of emissions control and is achievable, taking into account costs and reasonable commercial warranties for doors and related equipment; and (ii) door and jam cleaning practices. Notwithstanding subsection (i) of this section, the compliance date for such work practice regulations for coke oven batteries shall be not later than the date 3 years after November 15, 1990. (C) For coke oven batteries electing to qualify for an extension of the compliance date for standards promulgated under subsection (f) of this section in accordance with subsection (i)(8) of this section, the emission standards under this subsection for coke oven batteries shall require that coke oven batteries not exceed 8 per centum leaking doors, 1 per centum leaking lids, 5 per centum leaking offtakes, and 16 seconds visible emissions per charge, with no exclusion for emissions during the period after the closing of self-sealing doors. Page 139 of 177 Page 6250 Notwithstanding subsection (i) of this section, the compliance date for such emission standards for existing coke oven batteries seeking an extension shall be not later than the date 3 years after November 15, 1990. (9) Sources licensed by the Nuclear Regulatory Commission No standard for radionuclide emissions from any category or subcategory of facilities licensed by the Nuclear Regulatory Commission (or an Agreement State) is required to be promulgated under this section if the Administrator determines, by rule, and after consultation with the Nuclear Regulatory Commission, that the regulatory program established by the Nuclear Regulatory Commission pursuant to the Atomic Energy Act [42 U.S.C. 2011 et seq.] for such category or subcategory provides an ample margin of safety to protect the public health. Nothing in this subsection shall preclude or deny the right of any State or political subdivision thereof to adopt or enforce any standard or limitation respecting emissions of radionuclides which is more stringent than the standard or limitation in effect under section 7411 of this title or this section. (10) Effective date Emission standards or other regulations promulgated under this subsection shall be effective upon promulgation. (e) Schedule for standards and review (1) In general The Administrator shall promulgate regulations establishing emission standards for categories and subcategories of sources initially listed for regulation pursuant to subsection (c)(1) of this section as expeditiously as practicable, assuring that— (A) emission standards for not less than 40 categories and subcategories (not counting coke oven batteries) shall be promulgated not later than 2 years after November 15, 1990; (B) emission standards for coke oven batteries shall be promulgated not later than December 31, 1992; (C) emission standards for 25 per centum of the listed categories and subcategories shall be promulgated not later than 4 years after November 15, 1990; (D) emission standards for an additional 25 per centum of the listed categories and subcategories shall be promulgated not later than 7 years after November 15, 1990; and (E) emission standards for all categories and subcategories shall be promulgated not later than 10 years after November 15, 1990. (2) Priorities In determining priorities for promulgating standards under subsection (d) of this section, the Administrator shall consider— (A) the known or anticipated adverse effects of such pollutants on public health and the environment; (B) the quantity and location of emissions or reasonably anticipated emissions of hazardous air pollutants that each category or subcategory will emit; and Addendum – 018 USCA Case #12-1100 Page 6251 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE (C) the efficiency of grouping categories or subcategories according to the pollutants emitted, or the processes or technologies used. (3) Published schedule Not later than 24 months after November 15, 1990, and after opportunity for comment, the Administrator shall publish a schedule establishing a date for the promulgation of emission standards for each category and subcategory of sources listed pursuant to subsection (c)(1) and (3) of this section which shall be consistent with the requirements of paragraphs (1) and (2). The determination of priorities for the promulgation of standards pursuant to this paragraph is not a rulemaking and shall not be subject to judicial review, except that, failure to promulgate any standard pursuant to the schedule established by this paragraph shall be subject to review under section 7604 of this title. (4) Judicial review Notwithstanding section 7607 of this title, no action of the Administrator adding a pollutant to the list under subsection (b) of this section or listing a source category or subcategory under subsection (c) of this section shall be a final agency action subject to judicial review, except that any such action may be reviewed under such section 7607 of this title when the Administrator issues emission standards for such pollutant or category. (5) Publicly owned treatment works The Administrator shall promulgate standards pursuant to subsection (d) of this section applicable to publicly owned treatment works (as defined in title II of the Federal Water Pollution Control Act [33 U.S.C. 1281 et seq.]) not later than 5 years after November 15, 1990. (f) Standard to protect health and environment (1) Report Not later than 6 years after November 15, 1990, the Administrator shall investigate and report, after consultation with the Surgeon General and after opportunity for public comment, to Congress on— (A) methods of calculating the risk to public health remaining, or likely to remain, from sources subject to regulation under this section after the application of standards under subsection (d) of this section; (B) the public health significance of such estimated remaining risk and the technologically and commercially available methods and costs of reducing such risks; (C) the actual health effects with respect to persons living in the vicinity of sources, any available epidemiological or other health studies, risks presented by background concentrations of hazardous air pollutants, any uncertainties in risk assessment methodology or other health assessment technique, and any negative health or environmental consequences to the community of efforts to reduce such risks; and (D) recommendations as to legislation regarding such remaining risk. Page 140 of 177 § 7412 (2) Emission standards (A) If Congress does not act on any recommendation submitted under paragraph (1), the Administrator shall, within 8 years after promulgation of standards for each category or subcategory of sources pursuant to subsection (d) of this section, promulgate standards for such category or subcategory if promulgation of such standards is required in order to provide an ample margin of safety to protect public health in accordance with this section (as in effect before November 15, 1990) or to prevent, taking into consideration costs, energy, safety, and other relevant factors, an adverse environmental effect. Emission standards promulgated under this subsection shall provide an ample margin of safety to protect public health in accordance with this section (as in effect before November 15, 1990), unless the Administrator determines that a more stringent standard is necessary to prevent, taking into consideration costs, energy, safety, and other relevant factors, an adverse environmental effect. If standards promulgated pursuant to subsection (d) of this section and applicable to a category or subcategory of sources emitting a pollutant (or pollutants) classified as a known, probable or possible human carcinogen do not reduce lifetime excess cancer risks to the individual most exposed to emissions from a source in the category or subcategory to less than one in one million, the Administrator shall promulgate standards under this subsection for such source category. (B) Nothing in subparagraph (A) or in any other provision of this section shall be construed as affecting, or applying to the Administrator’s interpretation of this section, as in effect before November 15, 1990, and set forth in the Federal Register of September 14, 1989 (54 Federal Register 38044). (C) The Administrator shall determine whether or not to promulgate such standards and, if the Administrator decides to promulgate such standards, shall promulgate the standards 8 years after promulgation of the standards under subsection (d) of this section for each source category or subcategory concerned. In the case of categories or subcategories for which standards under subsection (d) of this section are required to be promulgated within 2 years after November 15, 1990, the Administrator shall have 9 years after promulgation of the standards under subsection (d) of this section to make the determination under the preceding sentence and, if required, to promulgate the standards under this paragraph. (3) Effective date Any emission standard established pursuant to this subsection shall become effective upon promulgation. (4) Prohibition No air pollutant to which a standard under this subsection applies may be emitted from any stationary source in violation of such standard, except that in the case of an existing source— (A) such standard shall not apply until 90 days after its effective date, and Addendum – 019 USCA Case #12-1100 § 7412 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE (B) the Administrator may grant a waiver permitting such source a period of up to 2 years after the effective date of a standard to comply with the standard if the Administrator finds that such period is necessary for the installation of controls and that steps will be taken during the period of the waiver to assure that the health of persons will be protected from imminent endangerment. (5) Area sources The Administrator shall not be required to conduct any review under this subsection or promulgate emission limitations under this subsection for any category or subcategory of area sources that is listed pursuant to subsection (c)(3) of this section and for which an emission standard is promulgated pursuant to subsection (d)(5) of this section. (6) Unique chemical substances In establishing standards for the control of unique chemical substances of listed pollutants without CAS numbers under this subsection, the Administrator shall establish such standards with respect to the health and environmental effects of the substances actually emitted by sources and direct transformation byproducts of such emissions in the categories and subcategories. (g) Modifications (1) Offsets (A) A physical change in, or change in the method of operation of, a major source which results in a greater than de minimis increase in actual emissions of a hazardous air pollutant shall not be considered a modification, if such increase in the quantity of actual emissions of any hazardous air pollutant from such source will be offset by an equal or greater decrease in the quantity of emissions of another hazardous air pollutant (or pollutants) from such source which is deemed more hazardous, pursuant to guidance issued by the Administrator under subparagraph (B). The owner or operator of such source shall submit a showing to the Administrator (or the State) that such increase has been offset under the preceding sentence. (B) The Administrator shall, after notice and opportunity for comment and not later than 18 months after November 15, 1990, publish guidance with respect to implementation of this subsection. Such guidance shall include an identification, to the extent practicable, of the relative hazard to human health resulting from emissions to the ambient air of each of the pollutants listed under subsection (b) of this section sufficient to facilitate the offset showing authorized by subparagraph (A). Such guidance shall not authorize offsets between pollutants where the increased pollutant (or more than one pollutant in a stream of pollutants) causes adverse effects to human health for which no safety threshold for exposure can be determined unless there are corresponding decreases in such types of pollutant(s). (2) Construction, reconstruction and modifications (A) After the effective date of a permit program under subchapter V of this chapter in Page 141 of 177 Page 6252 any State, no person may modify a major source of hazardous air pollutants in such State, unless the Administrator (or the State) determines that the maximum achievable control technology emission limitation under this section for existing sources will be met. Such determination shall be made on a case-by-case basis where no applicable emissions limitations have been established by the Administrator. (B) After the effective date of a permit program under subchapter V of this chapter in any State, no person may construct or reconstruct any major source of hazardous air pollutants, unless the Administrator (or the State) determines that the maximum achievable control technology emission limitation under this section for new sources will be met. Such determination shall be made on a caseby-case basis where no applicable emission limitations have been established by the Administrator. (3) Procedures for modifications The Administrator (or the State) shall establish reasonable procedures for assuring that the requirements applying to modifications under this section are reflected in the permit. (h) Work practice standards and other requirements (1) In general For purposes of this section, if it is not feasible in the judgment of the Administrator to prescribe or enforce an emission standard for control of a hazardous air pollutant or pollutants, the Administrator may, in lieu thereof, promulgate a design, equipment, work practice, or operational standard, or combination thereof, which in the Administrator’s judgment is consistent with the provisions of subsection (d) or (f) of this section. In the event the Administrator promulgates a design or equipment standard under this subsection, the Administrator shall include as part of such standard such requirements as will assure the proper operation and maintenance of any such element of design or equipment. (2) Definition For the purpose of this subsection, the phrase ‘‘not feasible to prescribe or enforce an emission standard’’ means any situation in which the Administrator determines that— (A) a hazardous air pollutant or pollutants cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State or local law, or (B) the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations. (3) Alternative standard If after notice and opportunity for comment, the owner or operator of any source establishes to the satisfaction of the Administrator that an alternative means of emission limita- Addendum – 020 USCA Case #12-1100 Page 6253 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE tion will achieve a reduction in emissions of any air pollutant at least equivalent to the reduction in emissions of such pollutant achieved under the requirements of paragraph (1), the Administrator shall permit the use of such alternative by the source for purposes of compliance with this section with respect to such pollutant. (4) Numerical standard required Any standard promulgated under paragraph (1) shall be promulgated in terms of an emission standard whenever it is feasible to promulgate and enforce a standard in such terms. (i) Schedule for compliance (1) Preconstruction and operating requirements After the effective date of any emission standard, limitation, or regulation under subsection (d), (f) or (h) of this section, no person may construct any new major source or reconstruct any existing major source subject to such emission standard, regulation or limitation unless the Administrator (or a State with a permit program approved under subchapter V of this chapter) determines that such source, if properly constructed, reconstructed and operated, will comply with the standard, regulation or limitation. (2) Special rule Notwithstanding the requirements of paragraph (1), a new source which commences construction or reconstruction after a standard, limitation or regulation applicable to such source is proposed and before such standard, limitation or regulation is promulgated shall not be required to comply with such promulgated standard until the date 3 years after the date of promulgation if— (A) the promulgated standard, limitation or regulation is more stringent than the standard, limitation or regulation proposed; and (B) the source complies with the standard, limitation, or regulation as proposed during the 3-year period immediately after promulgation. (3) Compliance schedule for existing sources (A) After the effective date of any emissions standard, limitation or regulation promulgated under this section and applicable to a source, no person may operate such source in violation of such standard, limitation or regulation except, in the case of an existing source, the Administrator shall establish a compliance date or dates for each category or subcategory of existing sources, which shall provide for compliance as expeditiously as practicable, but in no event later than 3 years after the effective date of such standard, except as provided in subparagraph (B) and paragraphs (4) through (8). (B) The Administrator (or a State with a program approved under subchapter V of this chapter) may issue a permit that grants an extension permitting an existing source up to 1 additional year to comply with standards under subsection (d) of this section if such additional period is necessary for the installa- Page 142 of 177 § 7412 tion of controls. An additional extension of up to 3 years may be added for mining waste operations, if the 4-year compliance time is insufficient to dry and cover mining waste in order to reduce emissions of any pollutant listed under subsection (b) of this section. (4) Presidential exemption The President may exempt any stationary source from compliance with any standard or limitation under this section for a period of not more than 2 years if the President determines that the technology to implement such standard is not available and that it is in the national security interests of the United States to do so. An exemption under this paragraph may be extended for 1 or more additional periods, each period not to exceed 2 years. The President shall report to Congress with respect to each exemption (or extension thereof) made under this paragraph. (5) Early reduction (A) The Administrator (or a State acting pursuant to a permit program approved under subchapter V of this chapter) shall issue a permit allowing an existing source, for which the owner or operator demonstrates that the source has achieved a reduction of 90 per centum or more in emissions of hazardous air pollutants (95 per centum in the case of hazardous air pollutants which are particulates) from the source, to meet an alternative emission limitation reflecting such reduction in lieu of an emission limitation promulgated under subsection (d) of this section for a period of 6 years from the compliance date for the otherwise applicable standard, provided that such reduction is achieved before the otherwise applicable standard under subsection (d) of this section is first proposed. Nothing in this paragraph shall preclude a State from requiring reductions in excess of those specified in this subparagraph as a condition of granting the extension authorized by the previous sentence. (B) An existing source which achieves the reduction referred to in subparagraph (A) after the proposal of an applicable standard but before January 1, 1994, may qualify under subparagraph (A), if the source makes an enforceable commitment to achieve such reduction before the proposal of the standard. Such commitment shall be enforceable to the same extent as a regulation under this section. (C) The reduction shall be determined with respect to verifiable and actual emissions in a base year not earlier than calendar year 1987, provided that, there is no evidence that emissions in the base year are artificially or substantially greater than emissions in other years prior to implementation of emissions reduction measures. The Administrator may allow a source to use a baseline year of 1985 or 1986 provided that the source can demonstrate to the satisfaction of the Administrator that emissions data for the source reflects verifiable data based on information for such source, received by the Administrator prior to November 15, 1990, pursuant to an information request issued under section 7414 of this title. (D) For each source granted an alternative emission limitation under this paragraph Addendum – 021 USCA Case #12-1100 § 7412 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE there shall be established by a permit issued pursuant to subchapter V of this chapter an enforceable emission limitation for hazardous air pollutants reflecting the reduction which qualifies the source for an alternative emission limitation under this paragraph. An alternative emission limitation under this paragraph shall not be available with respect to standards or requirements promulgated pursuant to subsection (f) of this section and the Administrator shall, for the purpose of determining whether a standard under subsection (f) of this section is necessary, review emissions from sources granted an alternative emission limitation under this paragraph at the same time that other sources in the category or subcategory are reviewed. (E) With respect to pollutants for which high risks of adverse public health effects may be associated with exposure to small quantities including, but not limited to, chlorinated dioxins and furans, the Administrator shall by regulation limit the use of offsetting reductions in emissions of other hazardous air pollutants from the source as counting toward the 90 per centum reduction in such high-risk pollutants qualifying for an alternative emissions limitation under this paragraph. (6) Other reductions Notwithstanding the requirements of this section, no existing source that has installed— (A) best available control technology (as defined in section 7479(3) of this title), or (B) technology required to meet a lowest achievable emission rate (as defined in section 7501 of this title), prior to the promulgation of a standard under this section applicable to such source and the same pollutant (or stream of pollutants) controlled pursuant to an action described in subparagraph (A) or (B) shall be required to comply with such standard under this section until the date 5 years after the date on which such installation or reduction has been achieved, as determined by the Administrator. The Administrator may issue such rules and guidance as are necessary to implement this paragraph. (7) Extension for new sources A source for which construction or reconstruction is commenced after the date an emission standard applicable to such source is proposed pursuant to subsection (d) of this section but before the date an emission standard applicable to such source is proposed pursuant to subsection (f) of this section shall not be required to comply with the emission standard under subsection (f) of this section until the date 10 years after the date construction or reconstruction is commenced. (8) Coke ovens (A) Any coke oven battery that complies with the emission limitations established under subsection (d)(8)(C) of this section, subparagraph (B), and subparagraph (C), and complies with the provisions of subparagraph (E), shall not be required to achieve emission limitations promulgated under subsection (f) of this section until January 1, 2020. Page 143 of 177 Page 6254 (B)(i) Not later than December 31, 1992, the Administrator shall promulgate emission limitations for coke oven emissions from coke oven batteries. Notwithstanding paragraph (3) of this subsection, the compliance date for such emission limitations for existing coke oven batteries shall be January 1, 1998. Such emission limitations shall reflect the lowest achievable emission rate as defined in section 7501 of this title for a coke oven battery that is rebuilt or a replacement at a coke oven plant for an existing battery. Such emission limitations shall be no less stringent than— (I) 3 per centum leaking doors (5 per centum leaking doors for six meter batteries); (II) 1 per centum leaking lids; (III) 4 per centum leaking offtakes; and (IV) 16 seconds visible emissions per charge, with an exclusion for emissions during the period after the closing of self-sealing oven doors (or the total mass emissions equivalent). The rulemaking in which such emission limitations are promulgated shall also establish an appropriate measurement methodology for determining compliance with such emission limitations, and shall establish such emission limitations in terms of an equivalent level of mass emissions reduction from a coke oven battery, unless the Administrator finds that such a mass emissions standard would not be practicable or enforceable. Such measurement methodology, to the extent it measures leaking doors, shall take into consideration alternative test methods that reflect the best technology and practices actually applied in the affected industries, and shall assure that the final test methods are consistent with the performance of such best technology and practices. (ii) If the Administrator fails to promulgate such emission limitations under this subparagraph prior to the effective date of such emission limitations, the emission limitations applicable to coke oven batteries under this subparagraph shall be— (I) 3 per centum leaking doors (5 per centum leaking doors for six meter batteries); (II) 1 per centum leaking lids; (III) 4 per centum leaking offtakes; and (IV) 16 seconds visible emissions per charge, or the total mass emissions equivalent (if the total mass emissions equivalent is determined to be practicable and enforceable), with no exclusion for emissions during the period after the closing of self-sealing oven doors. (C) Not later than January 1, 2007, the Administrator shall review the emission limitations promulgated under subparagraph (B) and revise, as necessary, such emission limitations to reflect the lowest achievable emission rate as defined in section 7501 of this title at the time for a coke oven battery that is rebuilt or a replacement at a coke oven plant for an existing battery. Such emission limitations shall be no less stringent than the emission limitation promulgated under subparagraph (B). Notwithstanding paragraph (2) of this subsection, the compliance date for such emission Addendum – 022 USCA Case #12-1100 Page 6255 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE limitations for existing coke oven batteries shall be January 1, 2010. (D) At any time prior to January 1, 1998, the owner or operator of any coke oven battery may elect to comply with emission limitations promulgated under subsection (f) of this section by the date such emission limitations would otherwise apply to such coke oven battery, in lieu of the emission limitations and the compliance dates provided under subparagraphs (B) and (C) of this paragraph. Any such owner or operator shall be legally bound to comply with such emission limitations promulgated under subsection (f) of this section with respect to such coke oven battery as of January 1, 2003. If no such emission limitations have been promulgated for such coke oven battery, the Administrator shall promulgate such emission limitations in accordance with subsection (f) of this section for such coke oven battery. (E) Coke oven batteries qualifying for an extension under subparagraph (A) shall make available not later than January 1, 2000, to the surrounding communities the results of any risk assessment performed by the Administrator to determine the appropriate level of any emission standard established by the Administrator pursuant to subsection (f) of this section. (F) Notwithstanding the provisions of this section, reconstruction of any source of coke oven emissions qualifying for an extension under this paragraph shall not subject such source to emission limitations under subsection (f) of this section more stringent than those established under subparagraphs (B) and (C) until January 1, 2020. For the purposes of this subparagraph, the term ‘‘reconstruction’’ includes the replacement of existing coke oven battery capacity with new coke oven batteries of comparable or lower capacity and lower potential emissions. (j) Equivalent emission limitation by permit (1) Effective date The requirements of this subsection shall apply in each State beginning on the effective date of a permit program established pursuant to subchapter V of this chapter in such State, but not prior to the date 42 months after November 15, 1990. (2) Failure to promulgate a standard In the event that the Administrator fails to promulgate a standard for a category or subcategory of major sources by the date established pursuant to subsection (e)(1) and (3) of this section, and beginning 18 months after such date (but not prior to the effective date of a permit program under subchapter V of this chapter), the owner or operator of any major source in such category or subcategory shall submit a permit application under paragraph (3) and such owner or operator shall also comply with paragraphs (5) and (6). (3) Applications By the date established by paragraph (2), the owner or operator of a major source subject to this subsection shall file an application for a permit. If the owner or operator of a source Page 144 of 177 § 7412 has submitted a timely and complete application for a permit required by this subsection, any failure to have a permit shall not be a violation of paragraph (2), unless the delay in final action is due to the failure of the applicant to timely submit information required or requested to process the application. The Administrator shall not later than 18 months after November 15, 1990, and after notice and opportunity for comment, establish requirements for applications under this subsection including a standard application form and criteria for determining in a timely manner the completeness of applications. (4) Review and approval Permit applications submitted under this subsection shall be reviewed and approved or disapproved according to the provisions of section 7661d of this title. In the event that the Administrator (or the State) disapproves a permit application submitted under this subsection or determines that the application is incomplete, the applicant shall have up to 6 months to revise the application to meet the objections of the Administrator (or the State). (5) Emission limitation The permit shall be issued pursuant to subchapter V of this chapter and shall contain emission limitations for the hazardous air pollutants subject to regulation under this section and emitted by the source that the Administrator (or the State) determines, on a case-by-case basis, to be equivalent to the limitation that would apply to such source if an emission standard had been promulgated in a timely manner under subsection (d) of this section. In the alternative, if the applicable criteria are met, the permit may contain an emissions limitation established according to the provisions of subsection (i)(5) of this section. For purposes of the preceding sentence, the reduction required by subsection (i)(5)(A) of this section shall be achieved by the date on which the relevant standard should have been promulgated under subsection (d) of this section. No such pollutant may be emitted in amounts exceeding an emission limitation contained in a permit immediately for new sources and, as expeditiously as practicable, but not later than the date 3 years after the permit is issued for existing sources or such other compliance date as would apply under subsection (i) of this section. (6) Applicability of subsequent standards If the Administrator promulgates an emission standard that is applicable to the major source prior to the date on which a permit application is approved, the emission limitation in the permit shall reflect the promulgated standard rather than the emission limitation determined pursuant to paragraph (5), provided that the source shall have the compliance period provided under subsection (i) of this section. If the Administrator promulgates a standard under subsection (d) of this section that would be applicable to the source in lieu of the emission limitation established by permit under this subsection after the date on which the permit has been issued, the Admin- Addendum – 023 USCA Case #12-1100 Page 6259 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE to pollutant loadings. For purposes of this subsection, ‘‘coastal waters’’ shall mean estuaries selected pursuant to section 320(a)(2)(A) of the Federal Water Pollution Control Act [33 U.S.C. 1330(a)(2)(A)] or listed pursuant to section 320(a)(2)(B) of such Act [33 U.S.C. 1330(a)(2)(B)] or estuarine research reserves designated pursuant to section 1461 of title 16. (5) Report Within 3 years of November 15, 1990, and biennially thereafter, the Administrator, in cooperation with the Under Secretary of Commerce for Oceans and Atmosphere, shall submit to the Congress a report on the results of any monitoring, studies, and investigations conducted pursuant to this subsection. Such report shall include, at a minimum, an assessment of— (A) the contribution of atmospheric deposition to pollution loadings in the Great Lakes, the Chesapeake Bay, Lake Champlain and coastal waters; (B) the environmental and public health effects of any pollution which is attributable to atmospheric deposition to the Great Lakes, the Chesapeake Bay, Lake Champlain and coastal waters; (C) the source or sources of any pollution to the Great Lakes, the Chesapeake Bay, Lake Champlain and coastal waters which is attributable to atmospheric deposition; (D) whether pollution loadings in the Great Lakes, the Chesapeake Bay, Lake Champlain or coastal waters cause or contribute to exceedances of drinking water standards pursuant to the Safe Drinking Water Act [42 U.S.C. 300f et seq.] or water quality standards pursuant to the Federal Water Pollution Control Act [33 U.S.C. 1251 et seq.] or, with respect to the Great Lakes, exceedances of the specific objectives of the Great Lakes Water Quality Agreement; and (E) a description of any revisions of the requirements, standards, and limitations pursuant to this chapter and other applicable Federal laws as are necessary to assure protection of human health and the environment. (6) Additional regulation As part of the report to Congress, the Administrator shall determine whether the other provisions of this section are adequate to prevent serious adverse effects to public health and serious or widespread environmental effects, including such effects resulting from indirect exposure pathways, associated with atmospheric deposition to the Great Lakes, the Chesapeake Bay, Lake Champlain and coastal waters of hazardous air pollutants (and their atmospheric transformation products). The Administrator shall take into consideration the tendency of such pollutants to bioaccumulate. Within 5 years after November 15, 1990, the Administrator shall, based on such report and determination, promulgate, in accordance with this section, such further emission standards or control measures as may be necessary and appropriate to prevent such effects, including effects due to bioaccumulation and indirect exposure pathways. Any requirements Page 145 of 177 § 7412 promulgated pursuant to this paragraph with respect to coastal waters shall only apply to the coastal waters of the States which are subject to section 7627(a) of this title. (n) Other provisions (1) Electric utility steam generating units (A) The Administrator shall perform a study of the hazards to public health reasonably anticipated to occur as a result of emissions by electric utility steam generating units of pollutants listed under subsection (b) of this section after imposition of the requirements of this chapter. The Administrator shall report the results of this study to the Congress within 3 years after November 15, 1990. The Administrator shall develop and describe in the Administrator’s report to Congress alternative control strategies for emissions which may warrant regulation under this section. The Administrator shall regulate electric utility steam generating units under this section, if the Administrator finds such regulation is appropriate and necessary after considering the results of the study required by this subparagraph. (B) The Administrator shall conduct, and transmit to the Congress not later than 4 years after November 15, 1990, a study of mercury emissions from electric utility steam generating units, municipal waste combustion units, and other sources, including area sources. Such study shall consider the rate and mass of such emissions, the health and environmental effects of such emissions, technologies which are available to control such emissions, and the costs of such technologies. (C) The National Institute of Environmental Health Sciences shall conduct, and transmit to the Congress not later than 3 years after November 15, 1990, a study to determine the threshold level of mercury exposure below which adverse human health effects are not expected to occur. Such study shall include a threshold for mercury concentrations in the tissue of fish which may be consumed (including consumption by sensitive populations) without adverse effects to public health. (2) Coke oven production technology study (A) The Secretary of the Department of Energy and the Administrator shall jointly undertake a 6-year study to assess coke oven production emission control technologies and to assist in the development and commercialization of technically practicable and economically viable control technologies which have the potential to significantly reduce emissions of hazardous air pollutants from coke oven production facilities. In identifying control technologies, the Secretary and the Administrator shall consider the range of existing coke oven operations and battery design and the availability of sources of materials for such coke ovens as well as alternatives to existing coke oven production design. (B) The Secretary and the Administrator are authorized to enter into agreements with persons who propose to develop, install and operate coke production emission control technologies which have the potential for signifi- Addendum – 024 USCA Case #12-1100 § 7412 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE cant emissions reductions of hazardous air pollutants provided that Federal funds shall not exceed 50 per centum of the cost of any project assisted pursuant to this paragraph. (C) On completion of the study, the Secretary shall submit to Congress a report on the results of the study and shall make recommendations to the Administrator identifying practicable and economically viable control technologies for coke oven production facilities to reduce residual risks remaining after implementation of the standard under subsection (d) of this section. (D) There are authorized to be appropriated $5,000,000 for each of the fiscal years 1992 through 1997 to carry out the program authorized by this paragraph. (3) Publicly owned treatment works The Administrator may conduct, in cooperation with the owners and operators of publicly owned treatment works, studies to characterize emissions of hazardous air pollutants emitted by such facilities, to identify industrial, commercial and residential discharges that contribute to such emissions and to demonstrate control measures for such emissions. When promulgating any standard under this section applicable to publicly owned treatment works, the Administrator may provide for control measures that include pretreatment of discharges causing emissions of hazardous air pollutants and process or product substitutions or limitations that may be effective in reducing such emissions. The Administrator may prescribe uniform sampling, modeling and risk assessment methods for use in implementing this subsection. (4) Oil and gas wells; pipeline facilities (A) Notwithstanding the provisions of subsection (a) of this section, emissions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not such units are in a contiguous area or under common control, to determine whether such units or stations are major sources, and in the case of any oil or gas exploration or production well (with its associated equipment), such emissions shall not be aggregated for any purpose under this section. (B) The Administrator shall not list oil and gas production wells (with its associated equipment) as an area source category under subsection (c) of this section, except that the Administrator may establish an area source category for oil and gas production wells located in any metropolitan statistical area or consolidated metropolitan statistical area with a population in excess of 1 million, if the Administrator determines that emissions of hazardous air pollutants from such wells present more than a negligible risk of adverse effects to public health. (5) Hydrogen sulfide The Administrator is directed to assess the hazards to public health and the environment resulting from the emission of hydrogen sul- Page 146 of 177 Page 6260 fide associated with the extraction of oil and natural gas resources. To the extent practicable, the assessment shall build upon and not duplicate work conducted for an assessment pursuant to section 8002(m) of the Solid Waste Disposal Act [42 U.S.C. 6982(m)] and shall reflect consultation with the States. The assessment shall include a review of existing State and industry control standards, techniques and enforcement. The Administrator shall report to the Congress within 24 months after November 15, 1990, with the findings of such assessment, together with any recommendations, and shall, as appropriate, develop and implement a control strategy for emissions of hydrogen sulfide to protect human health and the environment, based on the findings of such assessment, using authorities under this chapter including sections 3 7411 of this title and this section. (6) Hydrofluoric acid Not later than 2 years after November 15, 1990, the Administrator shall, for those regions of the country which do not have comprehensive health and safety regulations with respect to hydrofluoric acid, complete a study of the potential hazards of hydrofluoric acid and the uses of hydrofluoric acid in industrial and commercial applications to public health and the environment considering a range of events including worst-case accidental releases and shall make recommendations to the Congress for the reduction of such hazards, if appropriate. (7) RCRA facilities In the case of any category or subcategory of sources the air emissions of which are regulated under subtitle C of the Solid Waste Disposal Act [42 U.S.C. 6921 et seq.], the Administrator shall take into account any regulations of such emissions which are promulgated under such subtitle and shall, to the maximum extent practicable and consistent with the provisions of this section, ensure that the requirements of such subtitle and this section are consistent. (o) National Academy of Sciences study (1) Request of the Academy Within 3 months of November 15, 1990, the Administrator shall enter into appropriate arrangements with the National Academy of Sciences to conduct a review of— (A) risk assessment methodology used by the Environmental Protection Agency to determine the carcinogenic risk associated with exposure to hazardous air pollutants from source categories and subcategories subject to the requirements of this section; and (B) improvements in such methodology. (2) Elements to be studied In conducting such review, the National Academy of Sciences should consider, but not be limited to, the following— (A) the techniques used for estimating and describing the carcinogenic potency to humans of hazardous air pollutants; and 3 So in original. Probably should be ‘‘section’’. Addendum – 025 USCA Case #12-1100 Page 6281 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE action, indicating the purpose of such action. No State agency which receives notice under this paragraph of an action proposed to be taken may use the information contained in the notice to inform the person whose property is proposed to be affected of the proposed action. If the Administrator has reasonable basis for believing that a State agency is so using or will so use such information, notice to the agency under this paragraph is not required until such time as the Administrator determines the agency will no longer so use information contained in a notice under this paragraph. Nothing in this section shall be construed to require notification to any State agency of any action taken by the Administrator with respect to any standard, limitation, or other requirement which is not part of an applicable implementation plan or which was promulgated by the Administrator under section 7410(c) of this title. (2) Nothing in paragraph (1) shall be construed to provide that any failure of the Administrator to comply with the requirements of such paragraph shall be a defense in any enforcement action brought by the Administrator or shall make inadmissible as evidence in any such action any information or material obtained notwithstanding such failure to comply with such requirements. (July 14, 1955, ch. 360, title I, § 114, as added Pub. L. 91–604, § 4(a), Dec. 31, 1970, 84 Stat. 1687; amended Pub. L. 93–319, § 6(a)(4), June 22, 1974, 88 Stat. 259; Pub. L. 95–95, title I, §§ 109(d)(3), 113, title III, § 305(d), Aug. 7, 1977, 91 Stat. 701, 709, 776; Pub. L. 95–190, § 14(a)(22), (23), Nov. 16, 1977, 91 Stat. 1400; Pub. L. 101–549, title III, § 302(c), title VII, § 702(a), (b), Nov. 15, 1990, 104 Stat. 2574, 2680, 2681.) REFERENCES IN TEXT Section 7413(d) of this title, referred to in subsec. (d)(1), was amended generally by Pub. L. 101–549, title VII, § 701, Nov. 15, 1990, 104 Stat. 2672, and, as so amended, no longer relates to final compliance orders. CODIFICATION Section was formerly classified to section 1857c–9 of this title. AMENDMENTS 1990—Subsec. (a). Pub. L. 101–549, § 702(a)(1), which directed that ‘‘or’’ be struck out in first sentence immediately before ‘‘any emission standard under section 7412 of this title,’’ could not be executed because of the prior amendment by Pub. L. 101–549, § 302(c), see below. Pub. L. 101–549, § 702(a)(2), inserted ‘‘or any regulation under section 7429 of this title (relating to solid waste combustion),’’ before ‘‘(ii) of determining’’. Pub. L. 101–549, § 302(c), struck out ‘‘or’’ after ‘‘performance under section 7411 of this title,’’ and inserted ‘‘, or any regulation of solid waste combustion under section 7429 of this title,’’ after ‘‘standard under section 7412 of this title’’. Subsec. (a)(1). Pub. L. 101–549, § 702(a)(3), amended par. (1) generally. Prior to amendment, par. (1) read as follows: ‘‘the Administrator may require any person who owns or operates any emission source or who is subject to any requirement of this chapter (other than a manufacturer subject to the provisions of section 7525(c) or 7542 of this title) with respect to a provision of subchapter II of this chapter to (A) establish and maintain such records, (B) make such reports, (C) install, use, and maintain such monitoring equipment or methods, (D) sample such emissions (in accordance with such Page 147 of 177 § 7415 methods, at such locations, at such intervals, and in such manner as the Administrator shall prescribe), and (E) provide such other information as he may reasonably require; and’’. Subsec. (a)(3). Pub. L. 101–549, § 702(b), added par. (3). 1977—Subsec. (a). Pub. L. 95–190, § 14(a)(22), inserted reference to subchapter II of this chapter and ‘‘new’’ before ‘‘motor’’ in two places. Pub. L. 95–95, § 305(d), substituted ‘‘carrying out any provision of this chapter (except with respect to a manufacturer of motor vehicles or motor vehicle engines)’’ for ‘‘carrying out sections 119 or 303’’ in cl. (iii) preceding par. (1), substituted ‘‘any person subject to any requirement of this chapter (other than a manufacturer subject to the provisions of sections 7525(c) or 7542 of this title)’’ for ‘‘the owner or operator of any emission source’’ in par. (1), substituted ‘‘any premises of such person’’ for ‘‘any premises in which an emission source is located’’ in subpar. (A) of par. (2), and substituted ‘‘emissions which such person is required to sample’’ for ‘‘emissions which the owner or operator of such source is required to sample’’ in subpar. (B) of subpar. (2). Subsec. (a)(1). Pub. L. 95–190, § 14(a)(23), inserted reference to subchapter II of this chapter and ‘‘who owns or operates any emission source or who is’’ after ‘‘any person’’. Subsec. (b)(1). Pub. L. 95–95, § 109(d)(3), struck out ‘‘(except with respect to new sources owned or operated by the United States)’’ after ‘‘to carry out this section’’. Subsec. (d). Pub. L. 95–95, § 113, added subsec. (d). 1974—Subsec. (a). Pub. L. 93–319 inserted reference to section 119. EFFECTIVE DATE OF 1977 AMENDMENT Amendment by Pub. L. 95–95 effective Aug. 7, 1977, except as otherwise expressly provided, see section 406(d) of Pub. L. 95–95, set out as a note under section 7401 of this title. PENDING ACTIONS AND PROCEEDINGS Suits, actions, and other proceedings lawfully commenced by or against the Administrator or any other officer or employee of the United States in his official capacity or in relation to the discharge of his official duties under act July 14, 1955, the Clean Air Act, as in effect immediately prior to the enactment of Pub. L. 95–95 [Aug. 7, 1977], not to abate by reason of the taking effect of Pub. L. 95–95, see section 406(a) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. MODIFICATION OR RESCISSION OF RULES, REGULATIONS, DETERMINATIONS, CONTRACTS, CERTIFIORDERS, CATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER ACTIONS All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect immediately prior to the date of enactment of Pub. L. 95–95 [Aug. 7, 1977] to continue in full force and effect until modified or rescinded in accordance with act July 14, 1955, as amended by Pub. L. 95–95 [this chapter], see section 406(b) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. § 7415. International air pollution (a) Endangerment of public health or welfare in foreign countries from pollution emitted in United States Whenever the Administrator, upon receipt of reports, surveys or studies from any duly constituted international agency has reason to believe that any air pollutant or pollutants emit- Addendum – 026 CAA § 115 USCA Case #12-1100 § 7415 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE ted in the United States cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare in a foreign country or whenever the Secretary of State requests him to do so with respect to such pollution which the Secretary of State alleges is of such a nature, the Administrator shall give formal notification thereof to the Governor of the State in which such emissions originate. (b) Prevention or elimination of endangerment The notice of the Administrator shall be deemed to be a finding under section 7410(a)(2)(H)(ii) of this title which requires a plan revision with respect to so much of the applicable implementation plan as is inadequate to prevent or eliminate the endangerment referred to in subsection (a) of this section. Any foreign country so affected by such emission of pollutant or pollutants shall be invited to appear at any public hearing associated with any revision of the appropriate portion of the applicable implementation plan. (c) Reciprocity This section shall apply only to a foreign country which the Administrator determines has given the United States essentially the same rights with respect to the prevention or control of air pollution occurring in that country as is given that country by this section. (d) Recommendations Recommendations issued following any abatement conference conducted prior to August 7, 1977, shall remain in effect with respect to any pollutant for which no national ambient air quality standard has been established under section 7409 of this title unless the Administrator, after consultation with all agencies which were party to the conference, rescinds any such recommendation on grounds of obsolescence. (July 14, 1955, ch. 360, title I, § 115, formerly § 5, as added Pub. L. 88–206, § 1, Dec. 17, 1963, 77 Stat. 396; renumbered § 105 and amended Pub. L. 89–272, title I, §§ 101(2), (3), 102, Oct. 20, 1965, 79 Stat. 992, 995, renumbered § 108 and amended Pub. L. 90–148, § 2, Nov. 21, 1967, 81 Stat. 491, renumbered § 115 and amended Pub. L. 91–604, §§ 4(a), (b)(2)–(10), 15(c)(2), Dec. 31, 1970, 84 Stat. 1678, 1688, 1689, 1713; Pub. L. 95–95, title I, § 114, Aug. 7, 1977, 91 Stat. 710.) CODIFICATION Section was formerly classified to section 1857d of this title. AMENDMENTS 1977—Pub. L. 95–95 completely revised section by substituting provisions establishing a mechanism for the Administrator to trigger a revision of a State implementation plan under section 7410(a)(2)(H) upon a petition of an international agency or the Secretary of State if he finds that emissions originating in a State endanger the health or welfare of persons in a foreign country for provisions calling for the abatement of air pollution by means of conference procedures. 1970—Subsec. (a). Pub. L. 91–604, § 4(b)(2), inserted ‘‘and which is covered by subsection (b) or (c) of this section’’ after ‘‘persons’’. Subsec. (b). Pub. L. 91–604, §§ 4(b)(3), (4), (5), 15(c)(2), redesignated former subsec. (d)(1)(A), (B), and (C) as (b)(1), (2), and (3), substituted ‘‘Administrator’’ for Page 148 of 177 Page 6282 ‘‘Secretary’’ wherever appearing, and added subsec. (b)(4). Former subsec. (b), which related to the encouragement of municipal, State, and interstate action to abate air pollution, was struck out. Subsec. (c). Pub. L. 91–604, §§ 4(b)(3), (6), 15(c)(2), redesignated former subsec. (d)(1)(D) as (c) and substituted ‘‘Administrator’’ for ‘‘Secretary’’ and ‘‘Secretary of Health, Education, and Welfare’’ wherever appearing and ‘‘subsection’’ for ‘‘subparagraph’’ wherever appearing. Former subsec. (c), which related to the procedure for the promulgation of State air quality standards, was struck out. Subsec. (d). Pub. L. 91–604, §§ 4(b)(4), (6), (7), (8), 15(c)(2), redesignated former subsec. (d)(2) and (3) as (d)(1) and (2), in (d)(1) substituted ‘‘Administrator’’ for ‘‘Secretary’’ wherever appearing and ‘‘any conference under this section’’ for ‘‘such conference’’, and in (d)(2) substituted ‘‘Administrator’’ for ‘‘Secretary’’. Former subsec. (d)(1)(A), (B), and (C) were redesignated as (b)(1), (2), and (3), respectively, and subsec. (d)(1)(D) was redesignated as (c). Subsec. (e). Pub. L. 91–604, § 15(c)(2), substituted ‘‘Administrator’’ for ‘‘Secretary’’ wherever appearing. Subsec. (f). Pub. L. 91–604, § 15(c)(2), substituted ‘‘Administrator’’ for ‘‘Secretary’’ wherever appearing and ‘‘Environmental Protection Agency’’ for ‘‘Department of Health, Education, and Welfare’’. Subsec. (g). Pub. L. 91–604, §§ 4(b)(9), 15(c)(2), substituted ‘‘Administrator’’ for ‘‘Secretary’’ and ‘‘subsection (c)’’ for ‘‘subparagraph (D) of subsection (d)’’. Subsecs. (i), (j). Pub. L. 91–604, § 15(c)(2), substituted ‘‘Administrator’’ for ‘‘Secretary’’ wherever appearing. Subsec. (k). Pub. L. 91–604, § 4(b)(3), (10), substituted provisions relating to compliance with any requirement of an applicable implementation plan or with any standard prescribed under section 7411 of this title or section 7412 of this title, for provisions relating to the enjoining of imminent and substantial endangerment from pollution sources. 1967—Subsec. (b). Pub. L. 90–148 substituted reference to subsec. (c), (h), or (k) of this section for reference to subsec. (g) of this section. Subsecs. (c), (d). Pub. L. 90–148 added subsec. (c), redesignated former subsec. (c) as (d), inserted in par. (2) provisions for the delivery prior to the conference of a Federal report to agencies and interested parties covering matters before the conference, raised from three weeks to thirty days the required notice of the conference, and inserted provisions for notice by newspapers, presentation of views on the Federal report, and transcript of proceedings. Former subsec. (d) redesignated (e). Subsec. (e). Pub. L. 90–148 redesignated former subsec. (d) as (e). Former subsec. (e) redesignated (f) and amended. Subsec. (f). Pub. L. 90–148 redesignated former subsec. (e) as (f) and inserted in par. (1) requirement that all interested parties be given a reasonable opportunity to present evidence to the hearing board. Former subsec. (f) redesignated (g) and amended. Subsec. (g). Pub. L. 90–148 redesignated former subsec. (f) as (g) and substituted reference to subsec. (d) of this section for reference to subsec. (c) of this section. Former subsec. (g) redesignated (h) and amended. Subsec. (h). Pub. L. 90–148 redesignated former subsec. (g) as (h) and substituted reference to subsec. (g) of this section for reference to subsec. (f) of this section. Former subsec. (h) redesignated (i) and amended. Subsec. (i). Pub. L. 90–148 redesignated former subsec. (h) as (i) and substituted reference to subsec. (f) of this section for reference to subsec. (e) of this section and raised the per diem maximum from $50 to $100. Former subsec. (i) redesignated (j). Subsec. (j). Pub. L. 90–148 redesignated former subsec. (i) as (j). Subsec. (k). Pub. L. 90–148 added subsec. (k). 1965—Subsec. (b). Pub. L. 89–272, § 101(2), substituted ‘‘this title’’ for ‘‘this Act’’, which for purposes of codification has been changed to ‘‘this subchapter’’. Subsec. (c)(1)(D). Pub. L. 89–272, § 102(a), added subpar. (D). Addendum – 027 USCA Case #12-1100 § 7545 Document #1401252 have been expended by the State before the date on which any such grant was made. (July 14, 1955, ch. 360, title II, § 210, formerly § 209, as added Pub. L. 90–148, § 2, Nov. 21, 1967, 81 Stat. 502; renumbered and amended Pub. L. 91–604, §§ 8(a), 10(b), Dec. 31, 1970, 84 Stat. 1694, 1700; Pub. L. 95–95, title II, § 204, Aug. 7, 1977, 91 Stat. 754.) CODIFICATION Section was formerly classified to section 1857f–6b of this title. PRIOR PROVISIONS A prior section 210 of act July 14, 1955, was renumbered section 211 by Pub. L. 91–604 and is classified to section 7545 of this title. AMENDMENTS 1977—Pub. L. 95–95 inserted provision allowing grants to be made by way of reimbursement in any case in which amounts have been expended by States before the date on which the grants were made. 1970—Pub. L. 91–604, § 10(b), substituted provisions authorizing the Administrator to make grants to appropriate State agencies for the development and maintenance of effective vehicle emission devices and systems inspection and emission testing and control programs, for provisions authorizing the Secretary to make grants to appropriate State air pollution control agencies for the development of meaningful uniform motor vehicle emission device inspection and emission testing programs. EFFECTIVE DATE OF 1977 AMENDMENT Amendment by Pub. L. 95–95 effective Aug. 7, 1977, except as otherwise expressly provided, see section 406(d) of Pub. L. 95–95, set out as a note under section 7401 of this title. CAA § 211 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE § 7545. Regulation of fuels (a) Authority of Administrator to regulate The Administrator may by regulation designate any fuel or fuel additive (including any fuel or fuel additive used exclusively in nonroad engines or nonroad vehicles) and, after such date or dates as may be prescribed by him, no manufacturer or processor of any such fuel or additive may sell, offer for sale, or introduce into commerce such fuel or additive unless the Administrator has registered such fuel or additive in accordance with subsection (b) of this section. (b) Registration requirement (1) For the purpose of registration of fuels and fuel additives, the Administrator shall require— (A) the manufacturer of any fuel to notify him as to the commercial identifying name and manufacturer of any additive contained in such fuel; the range of concentration of any additive in the fuel; and the purpose-in-use of any such additive; and (B) the manufacturer of any additive to notify him as to the chemical composition of such additive. (2) For the purpose of registration of fuels and fuel additives, the Administrator shall, on a regular basis, require the manufacturer of any fuel or fuel additive— (A) to conduct tests to determine potential public health and environmental effects of the fuel or additive (including carcinogenic, teratogenic, or mutagenic effects); and Page 149 of 177 Page 6376 (B) to furnish the description of any analytical technique that can be used to detect and measure any additive in such fuel, the recommended range of concentration of such additive, and the recommended purpose-in-use of such additive, and such other information as is reasonable and necessary to determine the emissions resulting from the use of the fuel or additive contained in such fuel, the effect of such fuel or additive on the emission control performance of any vehicle, vehicle engine, nonroad engine or nonroad vehicle, or the extent to which such emissions affect the public health or welfare. Tests under subparagraph (A) shall be conducted in conformity with test procedures and protocols established by the Administrator. The result of such tests shall not be considered confidential. (3) Upon compliance with the provision of this subsection, including assurances that the Administrator will receive changes in the information required, the Administrator shall register such fuel or fuel additive. (4) STUDY ON CERTAIN FUEL ADDITIVES AND BLENDSTOCKS.— (A) IN GENERAL.—Not later than 2 years after August 8, 2005, the Administrator shall— (i) conduct a study on the effects on public health (including the effects on children, pregnant women, minority or low-income communities, and other sensitive populations), air quality, and water resources of increased use of, and the feasibility of using as substitutes for methyl tertiary butyl ether in gasoline— (I) ethyl tertiary butyl ether; (II) tertiary amyl methyl ether; (III) di-isopropyl ether; (IV) tertiary butyl alcohol; (V) other ethers and heavy alcohols, as determined by then 1 Administrator; (VI) ethanol; (VII) iso-octane; and (VIII) alkylates; and (ii) conduct a study on the effects on public health (including the effects on children, pregnant women, minority or low-income communities, and other sensitive populations), air quality, and water resources of the adjustment for ethanol-blended reformulated gasoline to the volatile organic compounds performance requirements that are applicable under paragraphs (1) and (3) of subsection (k) of this section; and (iii) submit to the Committee on Environment and Public Works of the Senate and the Committee on Energy and Commerce of the House of Representatives a report describing the results of the studies under clauses (i) and (ii). (B) CONTRACTS FOR STUDY.—In carrying out this paragraph, the Administrator may enter into one or more contracts with nongovernmental entities such as— (i) the national energy laboratories; and (ii) institutions of higher education (as defined in section 1001 of title 20). 1 So in original. Probably should be ‘‘the’’. Addendum – 028 USCA Case #12-1100 Page 6379 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE (d) Penalties and injunctions (1) Civil penalties Any person who violates subsection (a), (f), (g), (k), (l), (m), (n), or (o) of this section or the regulations prescribed under subsection (c), (h), (i), (k), (l), (m), (n), or (o) of this section or who fails to furnish any information or conduct any tests required by the Administrator under subsection (b) of this section shall be liable to the United States for a civil penalty of not more than the sum of $25,000 for every day of such violation and the amount of economic benefit or savings resulting from the violation. Any violation with respect to a regulation prescribed under subsection (c), (k), (l), (m), or (o) of this section which establishes a regulatory standard based upon a multiday averaging period shall constitute a separate day of violation for each and every day in the averaging period. Civil penalties shall be assessed in accordance with subsections (b) and (c) of section 7524 of this title. (2) Injunctive authority The district courts of the United States shall have jurisdiction to restrain violations of subsections (a), (f), (g), (k), (l), (m), (n), and (o) of this section and of the regulations prescribed under subsections (c), (h), (i), (k), (l), (m), (n), and (o) of this section, to award other appropriate relief, and to compel the furnishing of information and the conduct of tests required by the Administrator under subsection (b) of this section. Actions to restrain such violations and compel such actions shall be brought by and in the name of the United States. In any such action, subpoenas for witnesses who are required to attend a district court in any district may run into any other district. (e) Testing of fuels and fuel additives (1) Not later than one year after August 7, 1977, and after notice and opportunity for a public hearing, the Administrator shall promulgate regulations which implement the authority under subsection (b)(2)(A) and (B) of this section with respect to each fuel or fuel additive which is registered on the date of promulgation of such regulations and with respect to each fuel or fuel additive for which an application for registration is filed thereafter. (2) Regulations under subsection (b) of this section to carry out this subsection shall require that the requisite information be provided to the Administrator by each such manufacturer— (A) prior to registration, in the case of any fuel or fuel additive which is not registered on the date of promulgation of such regulations; or (B) not later than three years after the date of promulgation of such regulations, in the case of any fuel or fuel additive which is registered on such date. (3) In promulgating such regulations, the Administrator may— (A) exempt any small business (as defined in such regulations) from or defer or modify the requirements of, such regulations with respect to any such small business; (B) provide for cost-sharing with respect to the testing of any fuel or fuel additive which Page 150 of 177 § 7545 is manufactured or processed by two or more persons or otherwise provide for shared responsibility to meet the requirements of this section without duplication; or (C) exempt any person from such regulations with respect to a particular fuel or fuel additive upon a finding that any additional testing of such fuel or fuel additive would be duplicative of adequate existing testing. (f) New fuels and fuel additives (1)(A) Effective upon March 31, 1977, it shall be unlawful for any manufacturer of any fuel or fuel additive to first introduce into commerce, or to increase the concentration in use of, any fuel or fuel additive for general use in light duty motor vehicles manufactured after model year 1974 which is not substantially similar to any fuel or fuel additive utilized in the certification of any model year 1975, or subsequent model year, vehicle or engine under section 7525 of this title. (B) Effective upon November 15, 1990, it shall be unlawful for any manufacturer of any fuel or fuel additive to first introduce into commerce, or to increase the concentration in use of, any fuel or fuel additive for use by any person in motor vehicles manufactured after model year 1974 which is not substantially similar to any fuel or fuel additive utilized in the certification of any model year 1975, or subsequent model year, vehicle or engine under section 7525 of this title. (2) Effective November 30, 1977, it shall be unlawful for any manufacturer of any fuel to introduce into commerce any gasoline which contains a concentration of manganese in excess of .0625 grams per gallon of fuel, except as otherwise provided pursuant to a waiver under paragraph (4). (3) Any manufacturer of any fuel or fuel additive which prior to March 31, 1977, and after January 1, 1974, first introduced into commerce or increased the concentration in use of a fuel or fuel additive that would otherwise have been prohibited under paragraph (1)(A) if introduced on or after March 31, 1977 shall, not later than September 15, 1978, cease to distribute such fuel or fuel additive in commerce. During the period beginning 180 days after August 7, 1977, and before September 15, 1978, the Administrator shall prohibit, or restrict the concentration of any fuel additive which he determines will cause or contribute to the failure of an emission control device or system (over the useful life of any vehicle in which such device or system is used) to achieve compliance by the vehicle with the emission standards with respect to which it has been certified under section 7525 of this title. (4) The Administrator, upon application of any manufacturer of any fuel or fuel additive, may waive the prohibitions established under paragraph (1) or (3) of this subsection or the limitation specified in paragraph (2) of this subsection, if he determines that the applicant has established that such fuel or fuel additive or a specified concentration thereof, and the emission products of such fuel or fuel additive or specified concentration thereof, will not cause or contribute to a failure of any emission control device or system (over the useful life of the motor vehicle, Addendum – 029 USCA Case #12-1100 § 7545 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE motor vehicle engine, nonroad engine or nonroad vehicle in which such device or system is used) to achieve compliance by the vehicle or engine with the emission standards with respect to which it has been certified pursuant to sections 7525 and 7547(a) of this title. The Administrator shall take final action to grant or deny an application submitted under this paragraph, after public notice and comment, within 270 days of the receipt of such an application. (5) No action of the Administrator under this section may be stayed by any court pending judicial review of such action. (g) Misfueling (1) No person shall introduce, or cause or allow the introduction of, leaded gasoline into any motor vehicle which is labeled ‘‘unleaded gasoline only,’’ which is equipped with a gasoline tank filler inlet designed for the introduction of unleaded gasoline, which is a 1990 or later model year motor vehicle, or which such person knows or should know is a vehicle designed solely for the use of unleaded gasoline. (2) Beginning October 1, 1993, no person shall introduce or cause or allow the introduction into any motor vehicle of diesel fuel which such person knows or should know contains a concentration of sulfur in excess of 0.05 percent (by weight) or which fails to meet a cetane index minimum of 40 or such equivalent alternative aromatic level as prescribed by the Administrator under subsection (i)(2) of this section. (h) Reid Vapor Pressure requirements (1) Prohibition Not later than 6 months after November 15, 1990, the Administrator shall promulgate regulations making it unlawful for any person during the high ozone season (as defined by the Administrator) to sell, offer for sale, dispense, supply, offer for supply, transport, or introduce into commerce gasoline with a Reid Vapor Pressure in excess of 9.0 pounds per square inch (psi). Such regulations shall also establish more stringent Reid Vapor Pressure standards in a nonattainment area as the Administrator finds necessary to generally achieve comparable evaporative emissions (on a per-vehicle basis) in nonattainment areas, taking into consideration the enforceability of such standards, the need of an area for emission control, and economic factors. (2) Attainment areas The regulations under this subsection shall not make it unlawful for any person to sell, offer for supply, transport, or introduce into commerce gasoline with a Reid Vapor Pressure of 9.0 pounds per square inch (psi) or lower in any area designated under section 7407 of this title as an attainment area. Notwithstanding the preceding sentence, the Administrator may impose a Reid vapor pressure requirement lower than 9.0 pounds per square inch (psi) in any area, formerly an ozone nonattainment area, which has been redesignated as an attainment area. (3) Effective date; enforcement The regulations under this subsection shall provide that the requirements of this sub- Page 151 of 177 Page 6380 section shall take effect not later than the high ozone season for 1992, and shall include such provisions as the Administrator determines are necessary to implement and enforce the requirements of this subsection. (4) Ethanol waiver For fuel blends containing gasoline and 10 percent denatured anhydrous ethanol, the Reid vapor pressure limitation under this subsection shall be one pound per square inch (psi) greater than the applicable Reid vapor pressure limitations established under paragraph (1); Provided, however, That a distributor, blender, marketer, reseller, carrier, retailer, or wholesale purchaser-consumer shall be deemed to be in full compliance with the provisions of this subsection and the regulations promulgated thereunder if it can demonstrate (by showing receipt of a certification or other evidence acceptable to the Administrator) that— (A) the gasoline portion of the blend complies with the Reid vapor pressure limitations promulgated pursuant to this subsection; (B) the ethanol portion of the blend does not exceed its waiver condition under subsection (f)(4) of this section; and (C) no additional alcohol or other additive has been added to increase the Reid Vapor Pressure of the ethanol portion of the blend. (5) Exclusion from ethanol waiver (A) Promulgation of regulations Upon notification, accompanied by supporting documentation, from the Governor of a State that the Reid vapor pressure limitation established by paragraph (4) will increase emissions that contribute to air pollution in any area in the State, the Administrator shall, by regulation, apply, in lieu of the Reid vapor pressure limitation established by paragraph (4), the Reid vapor pressure limitation established by paragraph (1) to all fuel blends containing gasoline and 10 percent denatured anhydrous ethanol that are sold, offered for sale, dispensed, supplied, offered for supply, transported, or introduced into commerce in the area during the high ozone season. (B) Deadline for promulgation The Administrator shall promulgate regulations under subparagraph (A) not later than 90 days after the date of receipt of a notification from a Governor under that subparagraph. (C) Effective date (i) In general With respect to an area in a State for which the Governor submits a notification under subparagraph (A), the regulations under that subparagraph shall take effect on the later of— (I) the first day of the first high ozone season for the area that begins after the date of receipt of the notification; or (II) 1 year after the date of receipt of the notification. Addendum – 030 USCA Case #12-1100 § 7604 Document #1401252 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. MODIFICATION OR RESCISSION OF RULES, REGULATIONS, DETERMINATIONS, CONTRACTS, CERTIFIORDERS, CATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER ACTIONS All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect immediately prior to the date of enactment of Pub. L. 95–95 [Aug. 7, 1977] to continue in full force and effect until modified or rescinded in accordance with act July 14, 1955, as amended by Pub. L. 95–95 [this chapter], see section 406(b) of Pub. L. 95–95, set out as an Effective Date of 1977 Amendment note under section 7401 of this title. CAA § 304 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE § 7604. Citizen suits (a) Authority to bring civil action; jurisdiction Except as provided in subsection (b) of this section, any person may commence a civil action on his own behalf— (1) against any person (including (i) the United States, and (ii) any other governmental instrumentality or agency to the extent permitted by the Eleventh Amendment to the Constitution) who is alleged to have violated (if there is evidence that the alleged violation has been repeated) or to be in violation of (A) an emission standard or limitation under this chapter or (B) an order issued by the Administrator or a State with respect to such a standard or limitation, (2) against the Administrator where there is alleged a failure of the Administrator to perform any act or duty under this chapter which is not discretionary with the Administrator, or (3) against any person who proposes to construct or constructs any new or modified major emitting facility without a permit required under part C of subchapter I of this chapter (relating to significant deterioration of air quality) or part D of subchapter I of this chapter (relating to nonattainment) or who is alleged to have violated (if there is evidence that the alleged violation has been repeated) or to be in violation of any condition of such permit. The district courts shall have jurisdiction, without regard to the amount in controversy or the citizenship of the parties, to enforce such an emission standard or limitation, or such an order, or to order the Administrator to perform such act or duty, as the case may be, and to apply any appropriate civil penalties (except for actions under paragraph (2)). The district courts of the United States shall have jurisdiction to compel (consistent with paragraph (2) of this subsection) agency action unreasonably delayed, except that an action to compel agency action referred to in section 7607(b) of this title which is unreasonably delayed may only be filed in a United States District Court within the circuit in which such action would be reviewable under section 7607(b) of this title. In any such action for unreasonable delay, notice to the entities referred to in subsection (b)(1)(A) of this section shall be provided 180 days before commencing such action. Page 152 of 177 Page 6424 (b) Notice No action may be commenced— (1) under subsection (a)(1) of this section— (A) prior to 60 days after the plaintiff has given notice of the violation (i) to the Administrator, (ii) to the State in which the violation occurs, and (iii) to any alleged violator of the standard, limitation, or order, or (B) if the Administrator or State has commenced and is diligently prosecuting a civil action in a court of the United States or a State to require compliance with the standard, limitation, or order, but in any such action in a court of the United States any person may intervene as a matter of right.1 (2) under subsection (a)(2) of this section prior to 60 days after the plaintiff has given notice of such action to the Administrator, except that such action may be brought immediately after such notification in the case of an action under this section respecting a violation of section 7412(i)(3)(A) or (f)(4) of this title or an order issued by the Administrator pursuant to section 7413(a) of this title. Notice under this subsection shall be given in such manner as the Administrator shall prescribe by regulation. (c) Venue; intervention by Administrator; service of complaint; consent judgment (1) Any action respecting a violation by a stationary source of an emission standard or limitation or an order respecting such standard or limitation may be brought only in the judicial district in which such source is located. (2) In any action under this section, the Administrator, if not a party, may intervene as a matter of right at any time in the proceeding. A judgment in an action under this section to which the United States is not a party shall not, however, have any binding effect upon the United States. (3) Whenever any action is brought under this section the plaintiff shall serve a copy of the complaint on the Attorney General of the United States and on the Administrator. No consent judgment shall be entered in an action brought under this section in which the United States is not a party prior to 45 days following the receipt of a copy of the proposed consent judgment by the Attorney General and the Administrator during which time the Government may submit its comments on the proposed consent judgment to the court and parties or may intervene as a matter of right. (d) Award of costs; security The court, in issuing any final order in any action brought pursuant to subsection (a) of this section, may award costs of litigation (including reasonable attorney and expert witness fees) to any party, whenever the court determines such award is appropriate. The court may, if a temporary restraining order or preliminary injunction is sought, require the filing of a bond or equivalent security in accordance with the Federal Rules of Civil Procedure. (e) Nonrestriction of other rights Nothing in this section shall restrict any right which any person (or class of persons) may have 1 So in original. The period probably should be ‘‘, or’’. Addendum – 031 USCA Case #12-1100 § 7607 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE SEC. 2. Designation of Facilities. (a) The Administrator of the Environmental Protection Agency (hereinafter referred to as ‘‘the Administrator’’) shall be responsible for the attainment of the purposes and objectives of this Order. (b) In carrying out his responsibilities under this Order, the Administrator shall, in conformity with all applicable requirements of law, designate facilities which have given rise to a conviction for an offense under section 113(c)(1) of the Air Act [42 U.S.C. 7413(c)(1)] or section 309(c) of the Water Act [33 U.S.C. 1319(c)]. The Administrator shall, from time to time, publish and circulate to all Federal agencies lists of those facilities, together with the names and addresses of the persons who have been convicted of such offenses. Whenever the Administrator determines that the condition which gave rise to a conviction has been corrected, he shall promptly remove the facility and the name and address of the person concerned from the list. SEC. 3. Contracts, Grants, or Loans. (a) Except as provided in section 8 of this Order, no Federal agency shall enter into any contract for the procurement of goods, materials, or services which is to be performed in whole or in part in a facility then designated by the Administrator pursuant to section 2. (b) Except as provided in section 8 of this Order, no Federal agency authorized to extend Federal assistance by way of grant, loan, or contract shall extend such assistance in any case in which it is to be used to support any activity or program involving the use of a facility then designated by the Administrator pursuant to section 2. SEC. 4. Procurement, Grant, and Loan Regulations. The Federal Procurement Regulations, the Armed Services Procurement Regulations, and to the extent necessary, any supplemental or comparable regulations issued by any agency of the Executive Branch shall, following consultation with the Administrator, be amended to require, as a condition of entering into, renewing, or extending any contract for the procurement of goods, materials, or services or extending any assistance by way of grant, loan, or contract, inclusion of a provision requiring compliance with the Air Act, the Water Act, and standards issued pursuant thereto in the facilities in which the contract is to be performed, or which are involved in the activity or program to receive assistance. SEC. 5. Rules and Regulations. The Administrator shall issue such rules, regulations, standards, and guidelines as he may deem necessary or appropriate to carry out the purposes of this Order. SEC. 6. Cooperation and Assistance. The head of each Federal agency shall take such steps as may be necessary to insure that all officers and employees of this agency whose duties entail compliance or comparable functions with respect to contracts, grants, and loans are familiar with the provisions of this Order. In addition to any other appropriate action, such officers and employees shall report promptly any condition in a facility which may involve noncompliance with the Air Act or the Water Act or any rules, regulations, standards, or guidelines issued pursuant to this Order to the head of the agency, who shall transmit such reports to the Administrator. SEC. 7. Enforcement. The Administrator may recommend to the Department of Justice or other appropriate agency that legal proceedings be brought or other appropriate action be taken whenever he becomes aware of a breach of any provision required, under the amendments issued pursuant to section 4 of this Order, to be included in a contract or other agreement. SEC. 8. Exemptions—Reports to Congress. (a) Upon a determination that the paramount interest of the United States so requires— (1) The head of a Federal agency may exempt any contract, grant, or loan, and, following consultation with the Administrator, any class of contracts, grants or loans from the provisions of this Order. In any such case, the head of the Federal agency granting such ex- Page 153 of 177 Page 6428 emption shall (A) promptly notify the Administrator of such exemption and the justification therefor; (B) review the necessity for each such exemption annually; and (C) report to the Administrator annually all such exemptions in effect. Exemptions granted pursuant to this section shall be for a period not to exceed one year. Additional exemptions may be granted for periods not to exceed one year upon the making of a new determination by the head of the Federal agency concerned. (2) The Administrator may, by rule or regulation, exempt any or all Federal agencies from any or all of the provisions of this Order with respect to any class or classes of contracts, grants, or loans, which (A) involve less than specified dollar amounts, or (B) have a minimal potential impact upon the environment, or (C) involve persons who are not prime contractors or direct recipients of Federal assistance by way of contracts, grants, or loans. (b) Federal agencies shall reconsider any exemption granted under subsection (a) whenever requested to do so by the Administrator. (c) The Administrator shall annually notify the President and the Congress of all exemptions granted, or in effect, under this Order during the preceding year. SEC. 9. Related Actions. The imposition of any sanction or penalty under or pursuant to this Order shall not relieve any person of any legal duty to comply with any provisions of the Air Act or the Water Act. SEC. 10. Applicability. This Order shall not apply to contracts, grants, or loans involving the use of facilities located outside the United States. SEC. 11. Uniformity. Rules, regulations, standards, and guidelines issued pursuant to this order and section 508 of the Water Act [33 U.S.C. 1368] shall, to the maximum extent feasible, be uniform with regulations issued pursuant to this order, Executive Order No. 11602 of June 29, 1971 [formerly set out above], and section 306 of the Air Act [this section]. SEC. 12. Order Superseded. Executive Order No. 11602 of June 29, 1971, is hereby superseded. RICHARD NIXON. § 7607. Administrative proceedings and judicial review (a) Administrative subpenas; confidentiality; witnesses In connection with any determination under section 7410(f) of this title, or for purposes of obtaining information under section 7521(b)(4) 1 or 7545(c)(3) of this title, any investigation, monitoring, reporting requirement, entry, compliance inspection, or administrative enforcement proceeding under the 2 chapter (including but not limited to section 7413, section 7414, section 7420, section 7429, section 7477, section 7524, section 7525, section 7542, section 7603, or section 7606 of this title),,3 the Administrator may issue subpenas for the attendance and testimony of witnesses and the production of relevant papers, books, and documents, and he may administer oaths. Except for emission data, upon a showing satisfactory to the Administrator by such owner or operator that such papers, books, documents, or information or particular part thereof, if made public, would divulge trade secrets or secret processes of such owner or operator, the Administrator shall consider such record, report, or information or particular portion thereof confidential in accordance with the purposes of section 1905 of title 18, except that such paper, book, document, or information may be dis1 See References in Text note below. in original. Probably should be ‘‘this’’. 3 So in original. 2 So Addendum – 032 CAA § 307 USCA Case #12-1100 Page 6429 Document #1401252 closed to other officers, employees, or authorized representatives of the United States concerned with carrying out this chapter, to persons carrying out the National Academy of Sciences’ study and investigation provided for in section 7521(c) of this title, or when relevant in any proceeding under this chapter. Witnesses summoned shall be paid the same fees and mileage that are paid witnesses in the courts of the United States. In case of contumacy or refusal to obey a subpena served upon any person under this subparagraph,4 the district court of the United States for any district in which such person is found or resides or transacts business, upon application by the United States and after notice to such person, shall have jurisdiction to issue an order requiring such person to appear and give testimony before the Administrator to appear and produce papers, books, and documents before the Administrator, or both, and any failure to obey such order of the court may be punished by such court as a contempt thereof. (b) Judicial review (1) A petition for review of action of the Administrator in promulgating any national primary or secondary ambient air quality standard, any emission standard or requirement under section 7412 of this title, any standard of performance or requirement under section 7411 of this title,,3 any standard under section 7521 of this title (other than a standard required to be prescribed under section 7521(b)(1) of this title), any determination under section 7521(b)(5) 1 of this title, any control or prohibition under section 7545 of this title, any standard under section 7571 of this title, any rule issued under section 7413, 7419, or under section 7420 of this title, or any other nationally applicable regulations promulgated, or final action taken, by the Administrator under this chapter may be filed only in the United States Court of Appeals for the District of Columbia. A petition for review of the Administrator’s action in approving or promulgating any implementation plan under section 7410 of this title or section 7411(d) of this title, any order under section 7411(j) of this title, under section 7412 of this title, under section 7419 of this title, or under section 7420 of this title, or his action under section 1857c–10(c)(2)(A), (B), or (C) of this title (as in effect before August 7, 1977) or under regulations thereunder, or revising regulations for enhanced monitoring and compliance certification programs under section 7414(a)(3) of this title, or any other final action of the Administrator under this chapter (including any denial or disapproval by the Administrator under subchapter I of this chapter) which is locally or regionally applicable may be filed only in the United States Court of Appeals for the appropriate circuit. Notwithstanding the preceding sentence a petition for review of any action referred to in such sentence may be filed only in the United States Court of Appeals for the District of Columbia if such action is based on a determination of nationwide scope or effect and if in taking such action the Administrator finds and pub4 So Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE in original. Probably should be ‘‘subsection,’’. Page 154 of 177 § 7607 lishes that such action is based on such a determination. Any petition for review under this subsection shall be filed within sixty days from the date notice of such promulgation, approval, or action appears in the Federal Register, except that if such petition is based solely on grounds arising after such sixtieth day, then any petition for review under this subsection shall be filed within sixty days after such grounds arise. The filing of a petition for reconsideration by the Administrator of any otherwise final rule or action shall not affect the finality of such rule or action for purposes of judicial review nor extend the time within which a petition for judicial review of such rule or action under this section may be filed, and shall not postpone the effectiveness of such rule or action. (2) Action of the Administrator with respect to which review could have been obtained under paragraph (1) shall not be subject to judicial review in civil or criminal proceedings for enforcement. Where a final decision by the Administrator defers performance of any nondiscretionary statutory action to a later time, any person may challenge the deferral pursuant to paragraph (1). (c) Additional evidence In any judicial proceeding in which review is sought of a determination under this chapter required to be made on the record after notice and opportunity for hearing, if any party applies to the court for leave to adduce additional evidence, and shows to the satisfaction of the court that such additional evidence is material and that there were reasonable grounds for the failure to adduce such evidence in the proceeding before the Administrator, the court may order such additional evidence (and evidence in rebuttal thereof) to be taken before the Administrator, in such manner and upon such terms and conditions as to 5 the court may deem proper. The Administrator may modify his findings as to the facts, or make new findings, by reason of the additional evidence so taken and he shall file such modified or new findings, and his recommendation, if any, for the modification or setting aside of his original determination, with the return of such additional evidence. (d) Rulemaking (1) This subsection applies to— (A) the promulgation or revision of any national ambient air quality standard under section 7409 of this title, (B) the promulgation or revision of an implementation plan by the Administrator under section 7410(c) of this title, (C) the promulgation or revision of any standard of performance under section 7411 of this title, or emission standard or limitation under section 7412(d) of this title, any standard under section 7412(f) of this title, or any regulation under section 7412(g)(1)(D) and (F) of this title, or any regulation under section 7412(m) or (n) of this title, (D) the promulgation of any requirement for solid waste combustion under section 7429 of this title, 5 So in original. The word ‘‘to’’ probably should not appear. Addendum – 033 USCA Case #12-1100 § 7607 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE (E) the promulgation or revision of any regulation pertaining to any fuel or fuel additive under section 7545 of this title, (F) the promulgation or revision of any aircraft emission standard under section 7571 of this title, (G) the promulgation or revision of any regulation under subchapter IV–A of this chapter (relating to control of acid deposition), (H) promulgation or revision of regulations pertaining to primary nonferrous smelter orders under section 7419 of this title (but not including the granting or denying of any such order), (I) promulgation or revision of regulations under subchapter VI of this chapter (relating to stratosphere and ozone protection), (J) promulgation or revision of regulations under part C of subchapter I of this chapter (relating to prevention of significant deterioration of air quality and protection of visibility), (K) promulgation or revision of regulations under section 7521 of this title and test procedures for new motor vehicles or engines under section 7525 of this title, and the revision of a standard under section 7521(a)(3) of this title, (L) promulgation or revision of regulations for noncompliance penalties under section 7420 of this title, (M) promulgation or revision of any regulations promulgated under section 7541 of this title (relating to warranties and compliance by vehicles in actual use), (N) action of the Administrator under section 7426 of this title (relating to interstate pollution abatement), (O) the promulgation or revision of any regulation pertaining to consumer and commercial products under section 7511b(e) of this title, (P) the promulgation or revision of any regulation pertaining to field citations under section 7413(d)(3) of this title, (Q) the promulgation or revision of any regulation pertaining to urban buses or the cleanfuel vehicle, clean-fuel fleet, and clean fuel programs under part C of subchapter II of this chapter, (R) the promulgation or revision of any regulation pertaining to nonroad engines or nonroad vehicles under section 7547 of this title, (S) the promulgation or revision of any regulation relating to motor vehicle compliance program fees under section 7552 of this title, (T) the promulgation or revision of any regulation under subchapter IV–A of this chapter (relating to acid deposition), (U) the promulgation or revision of any regulation under section 7511b(f) of this title pertaining to marine vessels, and (V) such other actions as the Administrator may determine. The provisions of section 553 through 557 and section 706 of title 5 shall not, except as expressly provided in this subsection, apply to actions to which this subsection applies. This subsection shall not apply in the case of any rule or circumstance referred to in subparagraphs (A) or (B) of subsection 553(b) of title 5. Page 155 of 177 Page 6430 (2) Not later than the date of proposal of any action to which this subsection applies, the Administrator shall establish a rulemaking docket for such action (hereinafter in this subsection referred to as a ‘‘rule’’). Whenever a rule applies only within a particular State, a second (identical) docket shall be simultaneously established in the appropriate regional office of the Environmental Protection Agency. (3) In the case of any rule to which this subsection applies, notice of proposed rulemaking shall be published in the Federal Register, as provided under section 553(b) of title 5, shall be accompanied by a statement of its basis and purpose and shall specify the period available for public comment (hereinafter referred to as the ‘‘comment period’’). The notice of proposed rulemaking shall also state the docket number, the location or locations of the docket, and the times it will be open to public inspection. The statement of basis and purpose shall include a summary of— (A) the factual data on which the proposed rule is based; (B) the methodology used in obtaining the data and in analyzing the data; and (C) the major legal interpretations and policy considerations underlying the proposed rule. The statement shall also set forth or summarize and provide a reference to any pertinent findings, recommendations, and comments by the Scientific Review Committee established under section 7409(d) of this title and the National Academy of Sciences, and, if the proposal differs in any important respect from any of these recommendations, an explanation of the reasons for such differences. All data, information, and documents referred to in this paragraph on which the proposed rule relies shall be included in the docket on the date of publication of the proposed rule. (4)(A) The rulemaking docket required under paragraph (2) shall be open for inspection by the public at reasonable times specified in the notice of proposed rulemaking. Any person may copy documents contained in the docket. The Administrator shall provide copying facilities which may be used at the expense of the person seeking copies, but the Administrator may waive or reduce such expenses in such instances as the public interest requires. Any person may request copies by mail if the person pays the expenses, including personnel costs to do the copying. (B)(i) Promptly upon receipt by the agency, all written comments and documentary information on the proposed rule received from any person for inclusion in the docket during the comment period shall be placed in the docket. The transcript of public hearings, if any, on the proposed rule shall also be included in the docket promptly upon receipt from the person who transcribed such hearings. All documents which become available after the proposed rule has been published and which the Administrator determines are of central relevance to the rulemaking shall be placed in the docket as soon as possible after their availability. (ii) The drafts of proposed rules submitted by the Administrator to the Office of Management Addendum – 034 USCA Case #12-1100 Page 6431 Document #1401252 Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE and Budget for any interagency review process prior to proposal of any such rule, all documents accompanying such drafts, and all written comments thereon by other agencies and all written responses to such written comments by the Administrator shall be placed in the docket no later than the date of proposal of the rule. The drafts of the final rule submitted for such review process prior to promulgation and all such written comments thereon, all documents accompanying such drafts, and written responses thereto shall be placed in the docket no later than the date of promulgation. (5) In promulgating a rule to which this subsection applies (i) the Administrator shall allow any person to submit written comments, data, or documentary information; (ii) the Administrator shall give interested persons an opportunity for the oral presentation of data, views, or arguments, in addition to an opportunity to make written submissions; (iii) a transcript shall be kept of any oral presentation; and (iv) the Administrator shall keep the record of such proceeding open for thirty days after completion of the proceeding to provide an opportunity for submission of rebuttal and supplementary information. (6)(A) The promulgated rule shall be accompanied by (i) a statement of basis and purpose like that referred to in paragraph (3) with respect to a proposed rule and (ii) an explanation of the reasons for any major changes in the promulgated rule from the proposed rule. (B) The promulgated rule shall also be accompanied by a response to each of the significant comments, criticisms, and new data submitted in written or oral presentations during the comment period. (C) The promulgated rule may not be based (in part or whole) on any information or data which has not been placed in the docket as of the date of such promulgation. (7)(A) The record for judicial review shall consist exclusively of the material referred to in paragraph (3), clause (i) of paragraph (4)(B), and subparagraphs (A) and (B) of paragraph (6). (B) Only an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review. If the person raising an objection can demonstrate to the Administrator that it was impracticable to raise such objection within such time or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule, the Administrator shall convene a proceeding for reconsideration of the rule and provide the same procedural rights as would have been afforded had the information been available at the time the rule was proposed. If the Administrator refuses to convene such a proceeding, such person may seek review of such refusal in the United States court of appeals for the appropriate circuit (as provided in subsection (b) of this section). Such reconsideration shall not postpone the effectiveness of the rule. The effectiveness of the rule may be stayed during such reconsideration, however, by the Administrator or the court for a period not to exceed three months. Page 156 of 177 § 7607 (8) The sole forum for challenging procedural determinations made by the Administrator under this subsection shall be in the United States court of appeals for the appropriate circuit (as provided in subsection (b) of this section) at the time of the substantive review of the rule. No interlocutory appeals shall be permitted with respect to such procedural determinations. In reviewing alleged procedural errors, the court may invalidate the rule only if the errors were so serious and related to matters of such central relevance to the rule that there is a substantial likelihood that the rule would have been significantly changed if such errors had not been made. (9) In the case of review of any action of the Administrator to which this subsection applies, the court may reverse any such action found to be— (A) arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law; (B) contrary to constitutional right, power, privilege, or immunity; (C) in excess of statutory jurisdiction, authority, or limitations, or short of statutory right; or (D) without observance of procedure required by law, if (i) such failure to observe such procedure is arbitrary or capricious, (ii) the requirement of paragraph (7)(B) has been met, and (iii) the condition of the last sentence of paragraph (8) is met. (10) Each statutory deadline for promulgation of rules to which this subsection applies which requires promulgation less than six months after date of proposal may be extended to not more than six months after date of proposal by the Administrator upon a determination that such extension is necessary to afford the public, and the agency, adequate opportunity to carry out the purposes of this subsection. (11) The requirements of this subsection shall take effect with respect to any rule the proposal of which occurs after ninety days after August 7, 1977. (e) Other methods of judicial review not authorized Nothing in this chapter shall be construed to authorize judicial review of regulations or orders of the Administrator under this chapter, except as provided in this section. (f) Costs In any judicial proceeding under this section, the court may award costs of litigation (including reasonable attorney and expert witness fees) whenever it determines that such award is appropriate. (g) Stay, injunction, or similar relief in proceedings relating to noncompliance penalties In any action respecting the promulgation of regulations under section 7420 of this title or the administration or enforcement of section 7420 of this title no court shall grant any stay, injunctive, or similar relief before final judgment by such court in such action. (h) Public participation It is the intent of Congress that, consistent with the policy of subchapter II of chapter 5 of Addendum – 035 USCA Case #12-1100 § 7607 Document #1401252 title 5, the Administrator in promulgating any regulation under this chapter, including a regulation subject to a deadline, shall ensure a reasonable period for public participation of at least 30 days, except as otherwise expressly provided in section 6 7407(d), 7502(a), 7511(a) and (b), and 7512(a) and (b) of this title. (July 14, 1955, ch. 360, title III, § 307, as added Pub. L. 91–604, § 12(a), Dec. 31, 1970, 84 Stat. 1707; amended Pub. L. 92–157, title III, § 302(a), Nov. 18, 1971, 85 Stat. 464; Pub. L. 93–319, § 6(c), June 22, 1974, 88 Stat. 259; Pub. L. 95–95, title III, §§ 303(d), 305(a), (c), (f)–(h), Aug. 7, 1977, 91 Stat. 772, 776, 777; Pub. L. 95–190, § 14(a)(79), (80), Nov. 16, 1977, 91 Stat. 1404; Pub. L. 101–549, title I, §§ 108(p), 110(5), title III, § 302(g), (h), title VII, §§ 702(c), 703, 706, 707(h), 710(b), Nov. 15, 1990, 104 Stat. 2469, 2470, 2574, 2681–2684.) REFERENCES IN TEXT Section 7521(b)(4) of this title, referred to in subsec. (a), was repealed by Pub. L. 101–549, title II, § 230(2), Nov. 15, 1990, 104 Stat. 2529. Section 7521(b)(5) of this title, referred to in subsec. (b)(1), was repealed by Pub. L. 101–549, title II, § 230(3), Nov. 15, 1990, 104 Stat. 2529. Section 1857c–10(c)(2)(A), (B), or (C) of this title (as in effect before August 7, 1977), referred to in subsec. (b)(1), was in the original ‘‘section 119(c)(2)(A), (B), or (C) (as in effect before the date of enactment of the Clean Air Act Amendments of 1977)’’, meaning section 119 of act July 14, 1955, ch. 360, title I, as added June 22, 1974, Pub. L. 93–319, § 3, 88 Stat. 248, (which was classified to section 1857c–10 of this title) as in effect prior to the enactment of Pub. L. 95–95, Aug. 7, 1977, 91 Stat. 691, effective Aug. 7, 1977. Section 112(b)(1) of Pub. L. 95–95 repealed section 119 of act July 14, 1955, ch. 360, title I, as added by Pub. L. 93–319, and provided that all references to such section 119 in any subsequent enactment which supersedes Pub. L. 93–319 shall be construed to refer to section 113(d) of the Clean Air Act and to paragraph (5) thereof in particular which is classified to subsec. (d)(5) of section 7413 of this title. Section 7413(d) of this title was subsequently amended generally by Pub. L. 101–549, title VII, § 701, Nov. 15, 1990, 104 Stat. 2672, and, as so amended, no longer relates to final compliance orders. Section 117(b) of Pub. L. 95–95 added a new section 119 of act July 14, 1955, which is classified to section 7419 of this title. Part C of subchapter I of this chapter, referred to in subsec. (d)(1)(J), was in the original ‘‘subtitle C of title I’’, and was translated as reading ‘‘part C of title I’’ to reflect the probable intent of Congress, because title I does not contain subtitles. CODIFICATION In subsec. (h), ‘‘subchapter II of chapter 5 of title 5’’ was substituted for ‘‘the Administrative Procedures Act’’ on authority of Pub. L. 89–554, § 7(b), Sept. 6, 1966, 80 Stat. 631, the first section of which enacted Title 5, Government Organization and Employees. Section was formerly classified to section 1857h–5 of this title. PRIOR PROVISIONS A prior section 307 of act July 14, 1955, was renumbered section 314 by Pub. L. 91–604 and is classified to section 7614 of this title. Another prior section 307 of act July 14, 1955, ch. 360, title III, formerly § 14, as added Dec. 17, 1963, Pub. L. 88–206, § 1, 77 Stat. 401, was renumbered section 307 by Pub. L. 89–272, renumbered section 310 by Pub. L. 90–148, and renumbered section 317 by Pub. L. 91–604, and is set out as a Short Title note under section 7401 of this title. 6 So Filed: 10/23/2012 TITLE 42—THE PUBLIC HEALTH AND WELFARE in original. Probably should be ‘‘sections’’. Page 157 of 177 Page 6432 AMENDMENTS 1990—Subsec. (a). Pub. L. 101–549, § 703, struck out par. (1) designation at beginning, inserted provisions authorizing issuance of subpoenas and administration of oaths for purposes of investigations, monitoring, reporting requirements, entries, compliance inspections, or administrative enforcement proceedings under this chapter, and struck out ‘‘or section 7521(b)(5)’’ after ‘‘section 7410(f)’’. Subsec. (b)(1). Pub. L. 101–549, § 706(2), which directed amendment of second sentence by striking ‘‘under section 7413(d) of this title’’ immediately before ‘‘under section 7419 of this title’’, was executed by striking ‘‘under section 7413(d) of this title,’’ before ‘‘under section 7419 of this title’’, to reflect the probable intent of Congress. Pub. L. 101–549, § 706(1), inserted at end: ‘‘The filing of a petition for reconsideration by the Administrator of any otherwise final rule or action shall not affect the finality of such rule or action for purposes of judicial review nor extend the time within which a petition for judicial review of such rule or action under this section may be filed, and shall not postpone the effectiveness of such rule or action.’’ Pub. L. 101–549, § 702(c), inserted ‘‘or revising regulations for enhanced monitoring and compliance certification programs under section 7414(a)(3) of this title,’’ before ‘‘or any other final action of the Administrator’’. Pub. L. 101–549, § 302(g), substituted ‘‘section 7412’’ for ‘‘section 7412(c)’’. Subsec. (b)(2). Pub. L. 101–549, § 707(h), inserted sentence at end authorizing challenge to deferrals of performance of nondiscretionary statutory actions. Subsec. (d)(1)(C). Pub. L. 101–549, § 110(5)(A), amended subpar. (C) generally. Prior to amendment, subpar. (C) read as follows: ‘‘the promulgation or revision of any standard of performance under section 7411 of this title or emission standard under section 7412 of this title,’’. Subsec. (d)(1)(D), (E). Pub. L. 101–549, § 302(h), added subpar. (D) and redesignated former subpar. (D) as (E). Former subpar. (E) redesignated (F). Subsec. (d)(1)(F). Pub. L. 101–549, § 302(h), redesignated subpar. (E) as (F). Former subpar. (F) redesignated (G). Pub. L. 101–549, § 110(5)(B), amended subpar. (F) generally. Prior to amendment, subpar. (F) read as follows: ‘‘promulgation or revision of regulations pertaining to orders for coal conversion under section 7413(d)(5) of this title (but not including orders granting or denying any such orders),’’. Subsec. (d)(1)(G), (H). Pub. L. 101–549, § 302(h), redesignated subpars. (F) and (G) as (G) and (H), respectively. Former subpar. (H) redesignated (I). Subsec. (d)(1)(I). Pub. L. 101–549, § 710(b), which directed that subpar. (H) be amended by substituting ‘‘subchapter VI of this chapter’’ for ‘‘part B of subchapter I of this chapter’’, was executed by making the substitution in subpar. (I), to reflect the probable intent of Congress and the intervening redesignation of subpar. (H) as (I) by Pub. L. 101–549, § 302(h), see below. Pub. L. 101–549, § 302(h), redesignated subpar. (H) as (I). Former subpar. (I) redesignated (J). Subsec. (d)(1)(J) to (M). Pub. L. 101–549, § 302(h), redesignated subpars. (I) to (L) as (J) to (M), respectively. Former subpar. (M) redesignated (N). Subsec. (d)(1)(N). Pub. L. 101–549, § 302(h), redesignated subpar. (M) as (N). Former subpar. (N) redesignated (O). Pub. L. 101–549, § 110(5)(C), added subpar. (N) and redesignated former subpar. (N) as (U). Subsec. (d)(1)(O) to (T). Pub. L. 101–549, § 302(h), redesignated subpars. (N) to (S) as (O) to (T), respectively. Former subpar. (T) redesignated (U). Pub. L. 101–549, § 110(5)(C), added subpars. (O) to (T). Subsec. (d)(1)(U). Pub. L. 101–549, § 302(h), redesignated subpar. (T) as (U). Former subpar. (U) redesignated (V). Pub. L. 101–549, § 110(5)(C), redesignated former subpar. (N) as (U). Subsec. (d)(1)(V). Pub. L. 101–549, § 302(h), redesignated subpar. (U) as (V). Addendum – 036 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 158 of 177 1676 PUBLIC LAW 31, 1970 [84 STAT. Public Law 91-604 December 31' 1970 AN ACT 17255] To amend the Clean Air Act to provide for a more effective program to improve the quality of the Nation?s air. Be it enacted by the Senate and House of Representatives of the United States of America in Congress assembled, That this Act may A (3:33:13: of be cited as the ?Clean Air Amendments of 1970?. 1970. RESEARCH SEC. 2-. Section 103 of the Clean Air Act (42 U.S.C. 1857, et 81 Stat- 436- seq.) is amended by adding at the end thereof the following new 42 USC 1857b. subsection In carrying out research pursuant to this Act, the Admin- .istrator all give special emphasis to research on the short- and long- term effects of air pollutants on public health and welfare. In the furtherance of such research, he shall conduct an accelerated research program? to improve knowledge of the contribution of air pol- lutants to the occurrence of adverse effects on health, including, but not limited to, behavioral, physiological, toxicological, and bio- chemical effects; and to improve knowledgeof the short- and long-term effects of air pollutants on welfare. In carrying out the provisions of this subsection the Admin- istrator may?- conduct epidemiological studies of the effects of air pol- lutants on mortality and morbidity; conduct clinical and laboratory studies on the immuno- logic, biochemical, physiological, and the toxic010gical effects including carcinogenic, teratogenic, and mutagenic effects of air pollutants; utilize, on a reimbursable basis, the facilities of existing Federal scienti?c laboratories and research centers; (D) utilize the authority contained in paragraphs (1) through (4) of subsection and consult with other appropriate Federal agencies to assure that research or studies conducted pursuant to this subsection will be coordinated with research and studies of such other Federal agencies. (3) In entering into contracts under this subsection, the Adminis- trator is authorized to contract for a term not to exceed 10 years in Appropriation- duration. For the purposes of this paragraph, there are authorized to be appropriated $15,000,000. Such amounts as are appropriated shall remain available until expended and shall be in addition to any other appropriations under this Act.? 42 USC 1357b'1- 1(b) Section 104(a) (1) of the Clean Air Act is amended to read as lows: (1) conduct and accelerate research prOgrams directed toward development of improved, low-cost techniques for?- (A) control of combustion byproducts of fuels, (B) removal of potential air pollutants from fuels prior to combustion, EC) control of emissions from the evaporation of fuels, D) improving the ef?ciency of fuels combustion so as to decrease atmospheric emissions, and (E) producmg or new fuels which, when used, result in decreased atmospheric emissions.? Addendum 037 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Page 159 of 177 84 PUBLIC LAW 31, 1970 1685 EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 112. For purposes of this section? Definiti?ms- (1) The term ?hazardous air pollutant? means an air pollutant to which no ambient air uality standard is applicable and which in the judgment of the dministrator may cause, or contribute to, an increase in mortality or an increase 1n serious irreversible, or incapacitating reversible, illness. (2) The term ?new source? means a stationary source the construction or modi?cation of which is commenced after the Administrator proposes regulations under this section estab- lishing an emission standard which will be applicable to such source. The terms ?stationary source?, ?modi?cation?, ?owner or operator? and ?existing source? shall have the same meaning as such terms have under section 111 Ante, p. 153 3. (1) (A) The Administrator shall, within 90 days after the date Half? Public 5" of enactment of the Clean Air Amendments of 1970, publish (and shall from time to time thereafter revise) a list which 1ncludes each hazardous air pollutant for which he intends to establish an emission standard under this section. Within 180 days after the inclusion of any air pollutant in 1 rsgu' such list, the Administrator shall publish proposed regulations estab- atms' earmg' lishing emission standards for such pollutant together with a notice of a public hearing within thirty days. Not later than 180 days after such publication, the Administrator shall prescribe an emission stand? ard for such pollutant, unless he ?nds, on the basis of information presented at such hearings, that such pollutant clearly is not a hazard- ous air pollutant. The Administrator shall establish any such standard at the level which in his judgment provides an ample margin of safety to protect the public health from such hazardous air pollutant. C) Any emission standard established pursuant to this section shall become effective upon promulgation. (2) The Administrator shall, from time to time, issue information on pollution control techniques for air pollutants subject to the pro- visions of this section. (1) After the effective date of any emission standard under th is section? A) no person may construct any new source or modify any existing source which, in the Administrator?s judgment, will emit an air pollutant to which such standard applies unless the Admin- istrator ?nds that such source if preperly operated will not cause emissions in violation of such standard, and B) no air pollutant to which such standard applies may be emitted from any stationary source in Violation of such standard, except that in the case of an existing source? i) such standard shall not apply until 90 days after its effective date, and (ii) the Administrator may grant a waiver ?permitting such source a period of up to two years after the ective date of a standard to comply with the standard, if he ?nds that such period is necessary for the installation of controls and that steps will be taken during the period of the waiver to assure that the health of persons will be protected from imminent endangerment. The President may exempt any stationary source from com- ex?ggtiggntial pliance with paragraph (1) for a period of not more than two years if he ?nds that the technology to implement such standards is not available and the operation of such source is required for reasons of national security. An exemption under this paragraph may be extended Extensim- Addendum 038 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 § 60.44 Page 160 of 177 40 CFR Ch. I (7–1–11 Edition) Where: PSSO2 = Prorated standard for SO2 when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels or from all fossil fuels and wood residue fired; y = Percentage of total heat input derived from liquid fossil fuel; and z = Percentage of total heat input derived from solid fossil fuel. (c) Compliance shall be based on the total heat input from all fossil fuels burned, including gaseous fuels. (d) As an alternate to meeting the requirements of paragraphs (a) and (b) of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.43Da(i)(3) of subpart Da of this part or comply with § 60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.43Da(i)(3) of subpart Da of this part or § 60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. (e) Units 1 and 2 (as defined in appendix G of this part) at the Newton Power Station owned or operated by the Central Illinois Public Service Company will be in compliance with paragraph (a)(2) of this section if Unit 1 and Unit 2 individually comply with paragraph (a)(2) of this section or if the combined emission rate from Units 1 and 2 does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1 and 2. [60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5077, Jan. 28, 2009] PSNOX = § 60.44 Standard for nitrogen oxides (NOX). (a) Except as provided under paragraph (e) of this section, on and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain NOX, expressed as NO2 in excess of: (1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil fuel. (2) 129 ng/J heat input (0.30 lb/ MMBtu) derived from liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue. (3) 300 ng/J heat input (0.70 lb/ MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fossil fuel containing 25 percent, by weight, or more of coal refuse). (4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or lignite and wood residue (except as provided under paragraph (a)(5) of this section). (5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which is mined in North Dakota, South Dakota, or Montana and which is burned in a cyclone-fired unit. (b) Except as provided under paragraphs (c), (d), and (e) of this section, when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) is determined by proration using the following formula: w (260) + x (86) + y (130) + z (300) ( w + x + y + z) Where: PSNOX = Prorated standard for NOX when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired; w = Percentage of total heat input derived from lignite; x = Percentage of total heat input derived from gaseous fossil fuel; y = Percentage of total heat input derived from liquid fossil fuel; and z = Percentage of total heat input derived from solid fossil fuel (except lignite). (c) When a fossil fuel containing at least 25 percent, by weight, of coal refuse is burned in combination with gaseous, liquid, or other solid fossil fuel or wood residue, the standard for NOX does not apply. VerDate Mar<15>2010 10:48 Oct 11, 2011 Jkt 223149 PO 00000 Addendum – 039 Fmt 8010 Sfmt 8002 Q:\40\40V6.TXT Frm 00150 ofr150 PsN: PC150 ER13JN07.001 140 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 161 of 177 § 60.45 (d) Except as provided under paragraph (e) of this section, cyclone-fired units which burn fuels containing at least 25 percent of lignite that is mined in North Dakota, South Dakota, or Montana remain subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in combination with that lignite. (e) As an alternate to meeting the requirements of paragraphs (a), (b), and (d) of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.44Da(e)(3) of subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.44Da(e)(3) of subpart Da of this part. § 60.45 Emissions and fuel monitoring. (a) Each owner or operator shall install, calibrate, maintain, and operate continuous opacity monitoring system (COMS) for measuring opacity and a CEMS for measuring SO2 emissions, NOX emissions, and either oxygen (O2) or carbon dioxide (CO2) except as provided in paragraph (b) of this section. (b) Certain of the CEMS requirements under paragraph (a) of this section do not apply to owners or operators under the following conditions: (1) For a fossil-fuel-fired steam generator that burns only gaseous or liquid fossil fuel (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that does not use post-combustion technology to reduce emissions of SO2 or PM, CEMS for measuring the opacity of emissions and SO2 emissions are not required if the owner or operator monitors SO2 emissions by fuel sampling and analysis or fuel receipts. (2) For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS for measuring SO2 emissions is not required if the owner or operator monitors SO2 emissions by fuel sampling and analysis. (3) Notwithstanding § 60.13(b), installation of a CEMS for NOX may be delayed until after the initial performance tests under § 60.8 have been conducted. If the owner or operator dem- onstrates during the performance test that emissions of NOX are less than 70 percent of the applicable standards in § 60.44, a CEMS for measuring NOX emissions is not required. If the initial performance test results show that NOX emissions are greater than 70 percent of the applicable standard, the owner or operator shall install a CEMS for NOX within one year after the date of the initial performance tests under § 60.8 and comply with all other applicable monitoring requirements under this part. (4) If an owner or operator does not install any CEMS for sulfur oxides and NOX, as provided under paragraphs (b)(1) and (b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for measuring either O2 or CO2 is not required. (5) An owner or operator may petition the Administrator (in writing) to install a PM CEMS as an alternative to the CEMS for monitoring opacity emissions. (6) A CEMS for measuring the opacity of emissions is not required for a fossil fuel-fired steam generator that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected source are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day average basis. Owners and operators of affected sources electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (b)(6)(i) through (iv) of this section. (i) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (b)(6)(i)(A) through (D) of this section. (A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part. (B) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 141 VerDate Mar<15>2010 10:48 Oct 11, 2011 Jkt 223149 PO 00000 Addendum – 040 Fmt 8010 Sfmt 8002 Q:\40\40V6.TXT Frm 00151 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 162 of 177 § 63.2 ministrative, practical, or implementation problems and why the different definition would resolve those problems. The term ‘‘affected source,’’ as used in this part, is separate and distinct from any other use of that term in EPA regulations such as those implementing title IV of the Act. Affected source may be defined differently for part 63 than affected facility and stationary source in parts 60 and 61, respectively. This definition of ‘‘affected source,’’ and the procedures for adopting an alternative definition of ‘‘affected source,’’ shall apply to each section 112(d) standard for which the initial proposed rule is signed by the Administrator after June 30, 2002. Alternative emission limitation means conditions established pursuant to sections 112(i)(5) or 112(i)(6) of the Act by the Administrator or by a State with an approved permit program. Alternative emission standard means an alternative means of emission limitation that, after notice and opportunity for public comment, has been demonstrated by an owner or operator to the Administrator’s satisfaction to achieve a reduction in emissions of any air pollutant at least equivalent to the reduction in emissions of such pollutant achieved under a relevant design, equipment, work practice, or operational emission standard, or combination thereof, established under this part pursuant to section 112(h) of the Act. Alternative test method means any method of sampling and analyzing for an air pollutant that is not a test method in this chapter and that has been demonstrated to the Administrator’s satisfaction, using Method 301 in appendix A of this part, to produce results adequate for the Administrator’s determination that it may be used in place of a test method specified in this part. Approved permit program means a State permit program approved by the Administrator as meeting the requirements of part 70 of this chapter or a Federal permit program established in this chapter pursuant to title V of the Act (42 U.S.C. 7661). Area source means any stationary source of hazardous air pollutants that emission limitation are substantially as effective as the promulgated emission standard, the owner or operator may request the permitting authority to revise the source’s title V permit to reflect that the emission limitation in the permit satisfies the requirements of the promulgated emission standard. The process by which the permitting authority determines whether the section 112(j) emission limitation is substantially as effective as the promulgated emission standard must include, consistent with part 70 or 71 of this chapter, the opportunity for full public, EPA, and affected State review (including the opportunity for EPA’s objection) prior to the permit revision being finalized. A negative determination by the permitting authority constitutes final action for purposes of review and appeal under the applicable title V operating permit program. [59 FR 12430, Mar. 16, 1994, as amended at 67 FR 16595, Apr. 5, 2002] § 63.2 Definitions. The terms used in this part are defined in the Act or in this section as follows: Act means the Clean Air Act (42 U.S.C. 7401 et seq., as amended by Pub. L. 101–549, 104 Stat. 2399). Actual emissions is defined in subpart D of this part for the purpose of granting a compliance extension for an early reduction of hazardous air pollutants. Administrator means the Administrator of the United States Environmental Protection Agency or his or her authorized representative (e.g., a State that has been delegated the authority to implement the provisions of this part). Affected source, for the purposes of this part, means the collection of equipment, activities, or both within a single contiguous area and under common control that is included in a section 112(c) source category or subcategory for which a section 112(d) standard or other relevant standard is established pursuant to section 112 of the Act. Each relevant standard will define the ‘‘affected source,’’ as defined in this paragraph unless a different definition is warranted based on a published justification as to why this definition would result in significant ad- 13 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 041 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00023 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 § 63.2 Filed: 10/23/2012 Page 163 of 177 40 CFR Ch. I (7–1–12 Edition) Construction means the on-site fabrication, erection, or installation of an affected source. Construction does not include the removal of all equipment comprising an affected source from an existing location and reinstallation of such equipment at a new location. The owner or operator of an existing affected source that is relocated may elect not to reinstall minor ancillary equipment including, but not limited to, piping, ductwork, and valves. However, removal and reinstallation of an affected source will be construed as reconstruction if it satisfies the criteria for reconstruction as defined in this section. The costs of replacing minor ancillary equipment must be considered in determining whether the existing affected source is reconstructed. Continuous emission monitoring system (CEMS) means the total equipment that may be required to meet the data acquisition and availability requirements of this part, used to sample, condition (if applicable), analyze, and provide a record of emissions. Continuous monitoring system (CMS) is a comprehensive term that may include, but is not limited to, continuous emission monitoring systems, continuous opacity monitoring systems, continuous parameter monitoring systems, or other manual or automatic monitoring that is used for demonstrating compliance with an applicable regulation on a continuous basis as defined by the regulation. Continuous opacity monitoring system (COMS) means a continuous monitoring system that measures the opacity of emissions. Continuous parameter monitoring system means the total equipment that may be required to meet the data acquisition and availability requirements of this part, used to sample, condition (if applicable), analyze, and provide a record of process or control system parameters. Effective date means: (1) With regard to an emission standard established under this part, the date of promulgation in the FEDERAL REGISTER of such standard; or (2) With regard to an alternative emission limitation or equivalent emission limitation determined by the is not a major source as defined in this part. Commenced means, with respect to construction or reconstruction of an affected source, that an owner or operator has undertaken a continuous program of construction or reconstruction or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or reconstruction. Compliance date means the date by which an affected source is required to be in compliance with a relevant standard, limitation, prohibition, or any federally enforceable requirement established by the Administrator (or a State with an approved permit program) pursuant to section 112 of the Act. Compliance schedule means: (1) In the case of an affected source that is in compliance with all applicable requirements established under this part, a statement that the source will continue to comply with such requirements; or (2) In the case of an affected source that is required to comply with applicable requirements by a future date, a statement that the source will meet such requirements on a timely basis and, if required by an applicable requirement, a detailed schedule of the dates by which each step toward compliance will be reached; or (3) In the case of an affected source not in compliance with all applicable requirements established under this part, a schedule of remedial measures, including an enforceable sequence of actions or operations with milestones and a schedule for the submission of certified progress reports, where applicable, leading to compliance with a relevant standard, limitation, prohibition, or any federally enforceable requirement established pursuant to section 112 of the Act for which the affected source is not in compliance. This compliance schedule shall resemble and be at least as stringent as that contained in any judicial consent decree or administrative order to which the source is subject. Any such schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the applicable requirements on which it is based. 14 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 042 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00024 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 164 of 177 § 63.2 to section 112 of the Act as amended in 1990; (2) New source performance standards established pursuant to section 111 of the Act, and emission standards established pursuant to section 112 of the Act before it was amended in 1990; (3) All terms and conditions in a title V permit, including any provisions that limit a source’s potential to emit, unless expressly designated as not federally enforceable; (4) Limitations and conditions that are part of an approved State Implementation Plan (SIP) or a Federal Implementation Plan (FIP); (5) Limitations and conditions that are part of a Federal construction permit issued under 40 CFR 52.21 or any construction permit issued under regulations approved by the EPA in accordance with 40 CFR part 51; (6) Limitations and conditions that are part of an operating permit where the permit and the permitting program pursuant to which it was issued meet all of the following criteria: (i) The operating permit program has been submitted to and approved by EPA into a State implementation plan (SIP) under section 110 of the CAA; (ii) The SIP imposes a legal obligation that operating permit holders adhere to the terms and limitations of such permits and provides that permits which do not conform to the operating permit program requirements and the requirements of EPA’s underlying regulations may be deemed not ‘‘federally enforceable’’ by EPA; (iii) The operating permit program requires that all emission limitations, controls, and other requirements imposed by such permits will be at least as stringent as any other applicable limitations and requirements contained in the SIP or enforceable under the SIP, and that the program may not issue permits that waive, or make less stringent, any limitations or requirements contained in or issued pursuant to the SIP, or that are otherwise ‘‘federally enforceable’’; (iv) The limitations, controls, and requirements in the permit in question are permanent, quantifiable, and otherwise enforceable as a practical matter; and Administrator (or a State with an approved permit program), the date that the alternative emission limitation or equivalent emission limitation becomes effective according to the provisions of this part. Emission standard means a national standard, limitation, prohibition, or other regulation promulgated in a subpart of this part pursuant to sections 112(d), 112(h), or 112(f) of the Act. Emissions averaging is a way to comply with the emission limitations specified in a relevant standard, whereby an affected source, if allowed under a subpart of this part, may create emission credits by reducing emissions from specific points to a level below that required by the relevant standard, and those credits are used to offset emissions from points that are not controlled to the level required by the relevant standard. EPA means the United States Environmental Protection Agency. Equivalent emission limitation means any maximum achievable control technology emission limitation or requirements which are applicable to a major source of hazardous air pollutants and are adopted by the Administrator (or a State with an approved permit program) on a case-by-case basis, pursuant to section 112(g) or (j) of the Act. Excess emissions and continuous monitoring system performance report is a report that must be submitted periodically by an affected source in order to provide data on its compliance with relevant emission limits, operating parameters, and the performance of its continuous parameter monitoring systems. Existing source means any affected source that is not a new source. Federally enforceable means all limitations and conditions that are enforceable by the Administrator and citizens under the Act or that are enforceable under other statutes administered by the Administrator. Examples of federally enforceable limitations and conditions include, but are not limited to: (1) Emission standards, alternative emission standards, alternative emission limitations, and equivalent emission limitations established pursuant 15 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 043 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00025 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 § 63.2 Filed: 10/23/2012 Page 165 of 177 40 CFR Ch. I (7–1–12 Edition) (v) The permit in question was issued only after adequate and timely notice and opportunity for comment for EPA and the public. (7) Limitations and conditions in a State rule or program that has been approved by the EPA under subpart E of this part for the purposes of implementing and enforcing section 112; and (8) Individual consent agreements that the EPA has legal authority to create. Fixed capital cost means the capital needed to provide all the depreciable components of an existing source. Force majeure means, for purposes of § 63.7, an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents the owner or operator from complying with the regulatory requirement to conduct performance tests within the specified timeframe despite the affected facility’s best efforts to fulfill the obligation. Examples of such events are acts of nature, acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility. Fugitive emissions means those emissions from a stationary source that could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening. Under section 112 of the Act, all fugitive emissions are to be considered in determining whether a stationary source is a major source. Hazardous air pollutant means any air pollutant listed in or pursuant to section 112(b) of the Act. Issuance of a part 70 permit will occur, if the State is the permitting authority, in accordance with the requirements of part 70 of this chapter and the applicable, approved State permit program. When the EPA is the permitting authority, issuance of a title V permit occurs immediately after the EPA takes final action on the final permit. Major source means any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit considering controls, in the aggregate, 10 tons per year or more of any hazardous air pollutant or 25 tons per year or more of any combination of hazardous air pollutants, unless the Administrator establishes a lesser quantity, or in the case of radionuclides, different criteria from those specified in this sentence. Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner which causes, or has the potential to cause, the emission limitations in an applicable standard to be exceeded. Failures that are caused in part by poor maintenance or careless operation are not malfunctions. Monitoring means the collection and use of measurement data or other information to control the operation of a process or pollution control device or to verify a work practice standard relative to assuring compliance with applicable requirements. Monitoring is composed of four elements: (1) Indicator(s) of performance—the parameter or parameters you measure or observe for demonstrating proper operation of the pollution control measures or compliance with the applicable emissions limitation or standard. Indicators of performance may include direct or predicted emissions measurements (including opacity), operational parametric values that correspond to process or control device (and capture system) efficiencies or emissions rates, and recorded findings of inspection of work practice activities, materials tracking, or design characteristics. Indicators may be expressed as a single maximum or minimum value, a function of process variables (for example, within a range of pressure drops), a particular operational or work practice status (for example, a damper position, completion of a waste recovery task, materials tracking), or an interdependency between two or among more than two variables. (2) Measurement techniques—the means by which you gather and record information of or about the indicators of performance. The components of the measurement technique include the detector type, location and installation specifications, inspection procedures, 16 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 044 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00026 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 166 of 177 § 63.2 and quality assurance and quality control measures. Examples of measurement techniques include continuous emission monitoring systems, continuous opacity monitoring systems, continuous parametric monitoring systems, and manual inspections that include making records of process conditions or work practices. (3) Monitoring frequency—the number of times you obtain and record monitoring data over a specified time interval. Examples of monitoring frequencies include at least four points equally spaced for each hour for continuous emissions or parametric monitoring systems, at least every 10 seconds for continuous opacity monitoring systems, and at least once per operating day (or week, month, etc.) for work practice or design inspections. (4) Averaging time—the period over which you average and use data to verify proper operation of the pollution control approach or compliance with the emissions limitation or standard. Examples of averaging time include a 3-hour average in units of the emissions limitation, a 30-day rolling average emissions value, a daily average of a control device operational parametric range, and an instantaneous alarm. New affected source means the collection of equipment, activities, or both within a single contiguous area and under common control that is included in a section 112(c) source category or subcategory that is subject to a section 112(d) or other relevant standard for new sources. This definition of ‘‘new affected source,’’ and the criteria to be utilized in implementing it, shall apply to each section 112(d) standard for which the initial proposed rule is signed by the Administrator after June 30, 2002. Each relevant standard will define the term ‘‘new affected source,’’ which will be the same as the ‘‘affected source’’ unless a different collection is warranted based on consideration of factors including: (1) Emission reduction impacts of controlling individual sources versus groups of sources; (2) Cost effectiveness of controlling individual equipment; (3) Flexibility to accommodate common control strategies; (4) Cost/benefits of emissions averaging; (5) Incentives for pollution prevention; (6) Feasibility and cost of controlling processes that share common equipment (e.g., product recovery devices); (7) Feasibility and cost of monitoring; and (8) Other relevant factors. New source means any affected source the construction or reconstruction of which is commenced after the Administrator first proposes a relevant emission standard under this part establishing an emission standard applicable to such source. One-hour period, unless otherwise defined in an applicable subpart, means any 60-minute period commencing on the hour. Opacity means the degree to which emissions reduce the transmission of light and obscure the view of an object in the background. For continuous opacity monitoring systems, opacity means the fraction of incident light that is attenuated by an optical medium. Owner or operator means any person who owns, leases, operates, controls, or supervises a stationary source. Performance audit means a procedure to analyze blind samples, the content of which is known by the Administrator, simultaneously with the analysis of performance test samples in order to provide a measure of test data quality. Performance evaluation means the conduct of relative accuracy testing, calibration error testing, and other measurements used in validating the continuous monitoring system data. Performance test means the collection of data resulting from the execution of a test method (usually three emission test runs) used to demonstrate compliance with a relevant emission standard as specified in the performance test section of the relevant standard. Permit modification means a change to a title V permit as defined in regulations codified in this chapter to implement title V of the Act (42 U.S.C. 7661). Permit program means a comprehensive State operating permit system established pursuant to title V of the Act (42 U.S.C. 7661) and regulations codified 17 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 045 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00027 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 § 63.2 Filed: 10/23/2012 Page 167 of 177 40 CFR Ch. I (7–1–12 Edition) in part 70 of this chapter and applicable State regulations, or a comprehensive Federal operating permit system established pursuant to title V of the Act and regulations codified in this chapter. Permit revision means any permit modification or administrative permit amendment to a title V permit as defined in regulations codified in this chapter to implement title V of the Act (42 U.S.C. 7661). Permitting authority means: (1) The State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to carry out a permit program under part 70 of this chapter; or (2) The Administrator, in the case of EPA-implemented permit programs under title V of the Act (42 U.S.C. 7661). Pollution Prevention means source reduction as defined under the Pollution Prevention Act (42 U.S.C. 13101–13109). The definition is as follows: (1) Source reduction is any practice that: (i) Reduces the amount of any hazardous substance, pollutant, or contaminant entering any waste stream or otherwise released into the environment (including fugitive emissions) prior to recycling, treatment, or disposal; and (ii) Reduces the hazards to public health and the environment associated with the release of such substances, pollutants, or contaminants. (2) The term source reduction includes equipment or technology modifications, process or procedure modifications, reformulation or redesign of products, substitution of raw materials, and improvements in housekeeping, maintenance, training, or inventory control. (3) The term source reduction does not include any practice that alters the physical, chemical, or biological characteristics or the volume of a hazardous substance, pollutant, or contaminant through a process or activity which itself is not integral to and necessary for the production of a product or the providing of a service. Potential to emit means the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or oper- ational limitation on the capacity of the stationary source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation or the effect it would have on emissions is federally enforceable. Reconstruction, unless otherwise defined in a relevant standard, means the replacement of components of an affected or a previously nonaffected source to such an extent that: (1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable new source; and (2) It is technologically and economically feasible for the reconstructed source to meet the relevant standard(s) established by the Administrator (or a State) pursuant to section 112 of the Act. Upon reconstruction, an affected source, or a stationary source that becomes an affected source, is subject to relevant standards for new sources, including compliance dates, irrespective of any change in emissions of hazardous air pollutants from that source. Regulation promulgation schedule means the schedule for the promulgation of emission standards under this part, established by the Administrator pursuant to section 112(e) of the Act and published in the FEDERAL REGISTER. Relevant standard means: (1) An emission standard; (2) An alternative emission standard; (3) An alternative emission limitation; or (4) An equivalent emission limitation established pursuant to section 112 of the Act that applies to the collection of equipment, activities, or both regulated by such standard or limitation. A relevant standard may include or consist of a design, equipment, work practice, or operational requirement, or other measure, process, method, system, or technique (including prohibition of emissions) that the Administrator (or a State) establishes for new or existing sources to which such standard or limitation applies. Every relevant standard established pursuant 18 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 046 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00028 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 168 of 177 § 63.2 Source at a Performance Track member facility means a major or area source located at a facility which has been accepted by EPA for membership in the Performance Track Program (as described at www.epa.gov/ PerformanceTrack) and is still a member of the Program. The Performance Track Program is a voluntary program that encourages continuous environmental improvement through the use of environmental management systems, local community outreach, and measurable results. Standard conditions means a temperature of 293 K (68 °F) and a pressure of 101.3 kilopascals (29.92 in. Hg). Startup means the setting in operation of an affected source or portion of an affected source for any purpose. State means all non-Federal authorities, including local agencies, interstate associations, and State-wide programs, that have delegated authority to implement: (1) The provisions of this part and/or (2) the permit program established under part 70 of this chapter. The term State shall have its conventional meaning where clear from the context. Stationary source means any building, structure, facility, or installation which emits or may emit any air pollutant. Test method means the validated procedure for sampling, preparing, and analyzing for an air pollutant specified in a relevant standard as the performance test procedure. The test method may include methods described in an appendix of this chapter, test methods incorporated by reference in this part, or methods validated for an application through procedures in Method 301 of appendix A of this part. Title V permit means any permit issued, renewed, or revised pursuant to Federal or State regulations established to implement title V of the Act (42 U.S.C. 7661). A title V permit issued by a State permitting authority is called a part 70 permit in this part. Visible emission means the observation of an emission of opacity or optical density above the threshold of vision. Working day means any day on which Federal Government offices (or State government offices for a State that has to section 112 of the Act includes subpart A of this part, as provided by § 63.1(a)(4), and all applicable appendices of this part or of other parts of this chapter that are referenced in that standard. Responsible official means one of the following: (1) For a corporation: A president, secretary, treasurer, or vice president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision-making functions for the corporation, or a duly authorized representative of such person if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities and either: (i) The facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars); or (ii) The delegation of authority to such representative is approved in advance by the Administrator. (2) For a partnership or sole proprietorship: a general partner or the proprietor, respectively. (3) For a municipality, State, Federal, or other public agency: either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency includes the chief executive officer having responsibility for the overall operations of a principal geographic unit of the agency (e.g., a Regional Administrator of the EPA). (4) For affected sources (as defined in this part) applying for or subject to a title V permit: ‘‘responsible official’’ shall have the same meaning as defined in part 70 or Federal title V regulations in this chapter (42 U.S.C. 7661), whichever is applicable. Run means one of a series of emission or other measurements needed to determine emissions for a representative operating period or cycle as specified in this part. Shutdown means the cessation of operation of an affected source or portion of an affected source for any purpose. Six-minute period means, with respect to opacity determinations, any one of the 10 equal parts of a 1-hour period. 19 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 047 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00029 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 § 63.3 Filed: 10/23/2012 Page 169 of 177 40 CFR Ch. I (7–1–12 Edition) hr = hour in. = inch in. H2 O = inches of water K = 1,000 kcal = kilocalorie lb = pound lpm = liter per minute meq = milliequivalent min = minute MW = molecular weight oz = ounces ppb = parts per billion ppbw = parts per billion by weight ppbv = parts per billion by volume ppm = parts per million ppmw = parts per million by weight ppmv = parts per million by volume psia = pounds per square inch absolute psig = pounds per square inch gage °R = degree Rankine scf = cubic feet at standard conditions scfh = cubic feet at standard conditions per hour scm = cubic meter at standard conditions scmm = cubic meter at standard conditions per minute sec = second sq ft = square feet std = at standard conditions v/v = volume per volume yd2 = square yards yr = year obtained delegation under section 112(l)) are open for normal business. Saturdays, Sundays, and official Federal (or where delegated, State) holidays are not working days. [59 FR 12430, Mar. 16, 1994, as amended at 67 FR 16596, Apr. 5, 2002; 68 FR 32600, May 30, 2003; 69 FR 21752, Apr. 22, 2004; 72 FR 27443, May 16, 2007] § 63.3 Units and abbreviations. Used in this part are abbreviations and symbols of units of measure. These are defined as follows: (a) System International (SI) units of measure: A = ampere g = gram Hz = hertz J = joule °K = degree Kelvin kg = kilogram l = liter m = meter m3 = cubic meter mg = milligram = 10¥3 gram ml = milliliter = 10¥3 liter mm = millimeter = 10¥3 meter Mg = megagram = 106 gram = metric ton MJ = megajoule mol = mole N = newton ng = nanogram = 10¥9 gram nm = nanometer = 10¥9 meter Pa = pascal s = second V = volt W = watt Ω = ohm μg = microgram = 10¥6 gram μl = microliter = 10¥6 liter (c) Miscellaneous: act = actual avg = average I.D. = inside diameter M = molar N = normal O.D. = outside diameter % = percent [59 FR 12430, Mar. 16, 1994, as amended at 67 FR 16598, Apr. 5, 2002] § 63.4 Prohibited activities and circumvention. (a) Prohibited activities. (1) No owner or operator subject to the provisions of this part must operate any affected source in violation of the requirements of this part. Affected sources subject to and in compliance with either an extension of compliance or an exemption from compliance are not in violation of the requirements of this part. An extension of compliance can be granted by the Administrator under this part; by a State with an approved permit program; or by the President under section 112(i)(4) of the Act. (2) No owner or operator subject to the provisions of this part shall fail to keep records, notify, report, or revise reports as required under this part. (b) Other units of measure: Btu = British thermal unit °C = degree Celsius (centigrade) cal = calorie cfm = cubic feet per minute cc = cubic centimeter cu ft = cubic feet d = day dcf = dry cubic feet dcm = dry cubic meter dscf = dry cubic feet at standard conditions dscm = dry cubic meter at standard conditions eq = equivalent °F degree Fahrenheit ft = feet ft2 = square feet ft3 = cubic feet gal = gallon gr = grain g-eq = gram equivalent g-mole = gram mole 20 VerDate Mar<15>2010 19:36 Sep 17, 2012 Jkt 226155 PO 00000 Addendum – 048 Fmt 8010 Sfmt 8010 Q:\40\40V10.TXT Frm 00030 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 170 of 177 § 63.10042 as the performance test method (see definition of ‘‘test method’’ in § 63.2. (3) Approval of major changes to monitoring under § 63.8(f) and as defined in § 63.90. (4) Approval of major change to recordkeeping and reporting under § 63.10(e) and as defined in § 63.90. § 63.10042 What definitions apply to this subpart? Terms used in this subpart are defined in the Clean Air Act (CAA), in § 63.2 (the General Provisions), and in this section as follows: Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding. Anthracite coal means solid fossil fuel classified as anthracite coal by American Society of Testing and Materials (ASTM) Method D388–05, ‘‘Standard Classification of Coals by Rank’’ (incorporated by reference, see § 63.14). Bituminous coal means coal that is classified as bituminous according to ASTM Method D388–05, ‘‘Standard Classification of Coals by Rank’’ (incorporated by reference, see § 63.14). Boiler operating day means a 24-hour period between midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for the fuel to be combusted the entire 24hour period. Capacity factor for a liquid oil-fired EGU means the total annual heat input from oil divided by the product of maximum hourly heat input for the EGU, regardless of fuel, multiplied by 8,760 hours. Coal means all solid fuels classifiable as anthracite, bituminous, sub-bituminous, or lignite by ASTM Method D388–05, ‘‘Standard Classification of Coals by Rank’’ (incorporated by reference, see § 63.14), and coal refuse. Synthetic fuels derived from coal for the purpose of creating useful heat including but not limited to, coal derived gases (not meeting the definition of natural gas), solvent-refined coal, coaloil mixtures, and coal-water mixtures, are considered ‘‘coal’’ for the purposes of this subpart. Coal-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of ‘‘fossil fuel-fired’’ that burns coal for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year. Coal refuse means any by-product of coal mining, physical coal cleaning, and coal preparation operations (e.g., culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per pound) on a dry basis. Cogeneration means a steam-generating unit that simultaneously produces both electrical and useful thermal (or mechanical) energy from the same primary energy source. Cogeneration unit means a stationary, fossil fuel-fired EGU meeting the definition of ‘‘fossil fuel-fired’’ or stationary, integrated gasification combined cycle: (1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and (2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity: (i) For a topping-cycle cogeneration unit, (A) Useful thermal energy not less than 5 percent of total energy output; and (B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output. (ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input. 191 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 049 Fmt 8010 Sfmt 8010 Q:\40\40V15.TXT Frm 00201 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 § 63.10042 Page 171 of 177 40 CFR Ch. I (7–1–12 Edition) (3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel except biomass if the unit is a boiler. Combined-cycle gas stationary combustion turbine means a stationary combustion turbine system where heat from the turbine exhaust gases is recovered by a waste heat boiler. Common stack means the exhaust of emissions from two or more affected units through a single flue. Continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located in the continental United States. Deviation. (1) Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source: (i) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, work practice standard, or monitoring requirement; or (ii) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit. (2) A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the standard is up to the discretion of the entity responsible for enforcement of the standards. Distillate oil means fuel oils, including recycled oils, that comply with the specifications for fuel oil numbers 1 and 2, as defined by ASTM Method D396–10, ‘‘Standard Specification for Fuel Oils’’ (incorporated by reference, see § 63.14). Dry flue gas desulfurization technology, or dry FGD, or spray dryer absorber (SDA), or spray dryer, or dry scrubber means an add-on air pollution control system located downstream of the steam generating unit that injects a dry alkaline sorbent (dry sorbent injection) or sprays an alkaline sorbent slurry (spray dryer) to react with and neutralize acid gases such as SO2 and HCl in the exhaust stream forming a dry powder material. Alkaline sorbent injection systems in fluidized bed combustors (FBC) or circulating fluidized bed (CFB) boilers are included in this definition. Dry sorbent injection (DSI) means an add-on air pollution control system in which sorbent (e.g., conventional activated carbon, brominated activated carbon, Trona, hydrated lime, sodium carbonate, etc.) is injected into the flue gas steam upstream of a PM control device to react with and neutralize acid gases (such as SO2 and HCl) or Hg in the exhaust stream forming a dry powder material that may be removed in a primary or secondary PM control device. Electric Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with integrated gasification combined cycle gas turbines; nuclear steam generators are not included) for the purpose of powering a generator to produce electricity or electricity and other thermal energy. Electric utility steam generating unit (EGU) means a fossil fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is considered an electric utility steam generating unit. Emission limitation means any emissions limit, work practice standard, or operating limit. Excess emissions means, with respect to this subpart, results of any required measurements outside the applicable range (e.g., emissions limitations, parametric operating limits) that is permitted by this subpart. The values of measurements will be in the same units and averaging time as the values specified in this subpart for the limitations. Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60, 61, and 63; requirements within any 192 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 050 Fmt 8010 Sfmt 8010 Q:\40\40V15.TXT Frm 00202 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 172 of 177 § 63.10042 applicable state implementation plan; and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24. Flue gas desulfurization system means any add-on air pollution control system located downstream of the steam generating unit whose purpose or effect is to remove at least 50 percent of the SO2 in the exhaust gas stream. Fossil fuel means natural gas, oil, coal, and any form of solid, liquid, or gaseous fuel derived from such material. Fossil fuel-fired means an electric utility steam generating unit (EGU) that is capable of combusting more than 25 MW of fossil fuels. To be ‘‘capable of combusting’’ fossil fuels, an EGU would need to have these fuels allowed in its operating permit and have the appropriate fuel handling facilities on-site or otherwise available (e.g., coal handling equipment, including coal storage area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, fossil fuel-fired means any EGU that fired fossil fuels for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year after the applicable compliance date. Fuel type means each category of fuels that share a common name or classification. Examples include, but are not limited to, bituminous coal, subbituminous coal, lignite, anthracite, biomass, and residual oil. Individual fuel types received from different suppliers are not considered new fuel types. Fluidized bed boiler, or fluidized bed combustor, or circulating fluidized boiler, or CFB means a boiler utilizing a fluidized bed combustion process. Fluidized bed combustion means a process where a fuel is burned in a bed of granulated particles which are maintained in a mobile suspension by the upward flow of air and combustion products. Gaseous fuel includes, but is not limited to, natural gas, process gas, landfill gas, coal derived gas, solid oil-derived gas, refinery gas, and biogas. Generator means a device that produces electricity. Gross output means the gross useful work performed by the steam generated and, for an IGCC electric utility steam generating unit, the work performed by the stationary combustion turbines. For a unit generating only electricity, the gross useful work performed is the gross electrical output from the unit’s turbine/generator sets. For a cogeneration unit, the gross useful work performed is the gross electrical output, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls), or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process). Heat input means heat derived from combustion of fuel in an EGU (synthetic gas for an IGCC) and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources such as gas turbines, internal combustion engines, etc. Integrated gasification combined cycle electric utility steam generating unit or IGCC means an electric utility steam generating unit meeting the definition of ‘‘fossil fuel-fired’’ that burns a synthetic gas derived from coal and/or solid oil-derived fuel for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year in a combinedcycle gas turbine. No solid coal or solid oil-derived fuel is directly burned in the unit during operation. ISO conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals. Lignite coal means coal that is classified as lignite A or B according to ASTM Method D388–05, ‘‘Standard Classification of Coals by Rank’’ (incorporated by reference, see § 63.14). Limited-use liquid oil-fired subcategory means an oil-fired electric utility 193 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 051 Fmt 8010 Sfmt 8010 Q:\40\40V15.TXT Frm 00203 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 § 63.10042 Page 173 of 177 40 CFR Ch. I (7–1–12 Edition) steam generating unit with an annual capacity factor of less than 8 percent of its maximum or nameplate heat input, whichever is greater, averaged over a 24-month block contiguous period commencing April 16, 2015. Liquid fuel includes, but is not limited to, distillate oil and residual oil. Monitoring system malfunction or out of control period means any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earth’s surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 950 and 1,100 Btu per standard cubic foot. Natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Natural gas-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of ‘‘fossil fuel-fired’’ that is not a coal-fired, oil-fired, or IGCC electric utility steam generating unit and that burns natural gas for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year. Net-electric output means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis. Non-continental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands. Non-continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located outside the continental United States. Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As), Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead (Pb), Manganese (Mn), Nickel (Ni), and Selenium (Se). Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, solid oil-derived fuel (e.g., petroleum coke) and gases derived from solid oil-derived fuels (not meeting the definition of natural gas). Oil-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of ‘‘fossil fuel-fired’’ that is not a coal-fired electric utility steam generating unit and that burns oil for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year. Particulate matter or PM means any finely divided solid material as measured by the test methods specified under this subpart, or an alternative method. Pulverized coal (PC) boiler means an EGU in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the EGU where it is fired in suspension. Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6, as defined by ASTM Method D396–10, ‘‘Standard Specification for Fuel Oils’’ (incorporated by reference, see § 63.14). Responsible official means responsible official as defined in 40 CFR 70.2. Shutdown means the cessation of operation of a boiler for any purpose. Shutdown begins either when none of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use), or at the point of no fuel being fired in the boiler, whichever is earlier. Shutdown ends when there is both no electricity being generated and no fuel being fired in the boiler. Startup means either the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing 194 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 052 Fmt 8010 Sfmt 8010 Q:\40\40V15.TXT Frm 00204 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Environmental Protection Agency Page 174 of 177 § 63.10042 of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use). Stationary combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any regenerative/recuperative cycle stationary combustion turbine, the combustion turbine portion of any stationary cogeneration cycle combustion system, or the combustion turbine portion of any stationary combined cycle steam/electric generating system. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. Stationary combustion turbines do not include turbines located at a research or laboratory facility, if research is conducted on the turbine itself and the turbine is not being used to power other applications at the research or laboratory facility. Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuelfired steam generators associated with integrated gasification combined cycle gas turbines; nuclear steam generators are not included). Stoker means a unit consisting of a mechanically operated fuel feeding mechanism, a stationary or moving grate to support the burning of fuel and admit undergrate air to the fuel, an overfire air system to complete combustion, and an ash discharge system. There are two general types of stokers: underfeed and overfeed. Overfeed stokers include mass feed and spreader stokers. Subbituminous coal means coal that is classified as subbituminous A, B, or C according to ASTM Method D388–05, ‘‘Standard Classification of Coals by Rank’’ (incorporated by reference, see § 63.14). Unit designed for coal > 8,300 Btu/lb subcategory means any coal-fired EGU that is not a coal-fired EGU in the ‘‘unit designed for low rank virgin coal’’ subcategory. Unit designed for low rank virgin coal subcategory means any coal-fired EGU that is designed to burn and that is burning nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and operates at or near the mine that produces such coal. Unit designed to burn solid oil-derived fuel subcategory means any oil-fired EGU that burns solid oil-derived fuel. Voluntary consensus standards or VCS mean technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The EPA/ OAQPS has by precedent only used VCS that are written in English. Examples of VCS bodies are: American Society of Testing and Materials (ASTM), American Society of Mechanical Engineers (ASME), International Standards Organization (ISO), Standards Australia (AS), British Standards (BS), Canadian Standards (CSA), European Standard (EN or CEN) and German Engineering Standards (VDI). The types of standards that are not considered VCS are standards developed by: the U.S. states, e.g., California (CARB) and Texas (TCEQ); industry groups, such as American Petroleum Institute (API), Gas Processors Association (GPA), and Gas Research Institute (GRI); and other branches of the U.S. government, e.g., Department of Defense (DOD) and Department of Transportation (DOT). This does not preclude EPA from using standards developed by groups that are not VCS bodies within an EPA rule. When this occurs, EPA has done searches and reviews for VCS equivalent to these non-VCS methods. Wet flue gas desulfurization technology, or wet FGD, or wet scrubber means any add-on air pollution control device that is located downstream of the steam generating unit that mixes an aqueous stream or slurry with the exhaust gases from an EGU to control emissions of PM and/or to absorb and neutralize acid gases, such as SO2 and HCl. 195 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 053 Fmt 8010 Sfmt 8010 Q:\40\40V15.TXT Frm 00205 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Pt. 63, Subpt. UUUUU, Table 1 Page 175 of 177 40 CFR Ch. I (7–1–12 Edition) Work practice standard means any design, equipment, work practice, or operational standard, or combination thereof, which is promulgated pursuant to CAA section 112(h). [77 FR 9464, Feb. 16, 2012, as amended at 77 FR 23405, Apr. 19, 2012] TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS As stated in § 63.9991, you must comply with the following applicable emission limits: Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table . . . If your EGU is in this subcategory . . . For the following pollutants . . . You must meet the following emission limits and work practice standards . . . 1. Coal-fired unit not low rank virgin coal. a. Filterable particulate matter (PM). OR Total non-Hg HAP metals 7.0E–3 lb/MWh1 ..................... OR individual HAP metals: ........... OR Antimony (Sb) ........................ Arsenic (As) ........................... Beryllium (Be) ........................ Cadmium (Cd) ........................ Chromium (Cr) ....................... Cobalt (Co) ............................. Lead (Pb) ............................... Manganese (Mn) .................... Nickel (Ni) .............................. Selenium (Se) ........................ b. Hydrogen chloride (HC1) ... 8.0E–3 3.0E–3 6.0E–4 4.0E–4 7.0E–3 2.0E–3 2.0E–3 4.0E–3 4.0E–2 6.0E–3 4.0E–4 OR. Sulfur dioxide (SO2) 3 ............. c. Mercury (Hg) ...................... 4.0E–1 lb/MWh ...................... 2.0E–4 lb/GWh ....................... SO2 CEMS. Hg CEMS or sorbent trap monitoring system only. 7.0E–3 lb/MWh1 ..................... Collect a minimum of 4 dscm per run. 2. Coal-fired units low rank virgin coal. OR 6.0E–2 lb/GWh ....................... Collect a minimum of 4 dscm per run. Collect a minimum of 4 dscm per run. Collect a minimum of 3 dscm per run. lb/GW. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/MWh ...................... a. Filterable particulate matter (PM). OR Total non-Hg HAP metals ...... OR 6.0E–2 lb/GWh ....................... OR Individual HAP metals: OR ............................................ Antimony (Sb) ........................ Arsenic (As) ........................... Beryllium (Be) ........................ Cadmium (Cd) ........................ Chromium (Cr) ....................... Cobalt (Co) ............................. Lead (Pb) ............................... Manganese (Mn) .................... Nickel (Ni) .............................. Selenium (Se) ........................ b. Hydrogen chloride (HCl) .... 8.0E–3 3.0E–3 6.0E–4 4.0E–4 7.0E–3 2.0E–3 2.0E–3 4.0E–3 4.0E–2 6.0E–3 4.0E–4 OR Sulfur dioxide (SO2) 3 ............. 4.0E–1 lb/MWh ...................... lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/GWh. lb/MWh ...................... For Method 26A, collect a minimum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour. Collect a minimum of 4 dscm per run. Collect a minimum of 3 dscm per run. For Method 26A, collect a minimum of 3 dscm per run. For ASTM D6348–03 2 or Method 320, sample for a minimum of 1 hour. SO2 CEMS. 196 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 054 Fmt 8010 Sfmt 8002 Q:\40\40V15.TXT Frm 00206 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Environmental Protection Agency If your EGU is in this subcategory . . . Filed: 10/23/2012 Page 176 of 177 Pt. 63, Subpt. UUUUU, Table 3 For the following pollutants . . . You must meet the following emission limits and work practice standards . . . Selenium (Se) ........................ 1.2E0 lb/TBtu or 2.0E–2 lb/ GWh. 5.0E–3 lb/MMBtu or 8.0E–2 lb/MWh. b. Hydrogen chloride (HCl) .... OR Sulfur dioxide (SO2) 4 ............. c. Mercury (Hg) ...................... 3.0E–1 lb/MMBtu or 2.0E0 lb/ MWh. 2.0E–1 lb/TBtu or 2.0E–3 lb/ GWh. Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 . . . For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. SO2 CEMS. LEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or Sorbent trap monitoring system only. 1 For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must be increased nominally by a factor of two. 2 Gross electric output. 3 Incorporated by reference, see § 63.14. 4 You may not use the alternate SO limit if your EGU does not have some form of FGD system and SO CEMS installed. 2 2 [77 FR 23405, Apr. 19, 2012] TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS As stated in §§ 63.9991, you must comply with the following applicable work practice standards: If your EGU is . . . You must meet the following . . . 1. An existing EGU ..................................... Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar months if neural network combustion optimization software is employed, as specified in § 63.10021(e). 2. A new or reconstructed EGU .................. Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar months if neural network combustion optimization software is employed, as specified in § 63.10021(e). 3. A coal-fired, liquid oil-fired, or solid oilderived fuel-fired EGU during startup. You must operate all CMS during startup. Startup means either the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on site use). For startup of a unit, you must use clean fuels, either natural gas or distillate oil or a combination of clean fuels for ignition. Once you convert to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the applicable control technologies except dry scrubber and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to comply with relevant standards applicable during normal operation. You must comply with all applicable emissions limits at all times except for periods that meet the definitions of startup and shutdown in this subpart. You must keep records during periods of startup. You must provide reports concerning activities and periods of startup, as specified in § 63.10011(g) and § 63.10021(h) and (i). 203 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 055 Fmt 8010 Sfmt 8002 Q:\40\40V15.TXT Frm 00213 ofr150 PsN: PC150 USCA Case #12-1100 Document #1401252 Filed: 10/23/2012 Pt. 63, Subpt. UUUUU, Table 4 Page 177 of 177 40 CFR Ch. I (7–1–12 Edition) If your EGU is . . . You must meet the following . . . 4. A coal-fired, liquid oil-fired, or solid oilderived fuel-fired EGU during shutdown. You must operate all CMS during shutdown. Shutdown means the cessation of operation of a boiler for any purpose. Shutdown begins either when none of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use) or at the point of no fuel being fired in the boiler. Shutdown ends when there is both no electricity being generated and no fuel being fired in the boiler. During shutdown, you must operate all applicable control technologies while firing coal, residual oil, or solid oil-derived fuel. You must comply with all applicable emissions limits at all times except for periods that meet the definitions of startup and shutdown in this subpart. You must keep records during periods of startup. You must provide reports concerning activities and periods of startup, as specified in § 63.10011(g) and § 63.10021(h) and (i). TABLE 4 TO SUBPART UUUUU OF PART 63—OPERATING LIMITS FOR EGUS As stated in § 63.9991, you must comply with the applicable operating limits: If you demonstrate compliance using . . . You must meet these operating limits . . . 1. PM CPMS ............................................... Maintain the 30-boiler operating day rolling average PM CPMS output at or below the highest 1-hour average measured during the most recent performance test demonstrating compliance with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oil-fired units), or individual non-mercury HAP metals (individual HAP metals including Hg, for liquid oil-fired units) emissions limitation(s). TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources: 1 To conduct a performance test for the following pollutant . . . 1. Filterable Particulate matter (PM). You must perform the following activities, as applicable to your input- or output-based emission limit . . . Using . . . Emissions Testing .. a. Select sampling ports location and the number of traverse points. b. Determine velocity and volumetric flow-rate of the stack gas. c. Determine oxygen and carbon dioxide concentrations of the stack gas. d. Measure the moisture content of the stack gas. e. Measure the filterable PM concentration. f. Convert emissions concentration to lb/ MMBtu or lb/MWh emissions rates. OR PM CEMS OR a. Install, certify, operate, and maintain the PM CEMS. b. Install, certify, operate, and maintain the diluent gas, flow rate, and/or moisture monitoring systems. Using 2 . . . Method 1 at Appendix A–1 to part 60 of this chapter. Method 2, 2A, 2C, 2F, 2G or 2H at Appendix A–1 or A–2 to part 60 of this chapter. Method 3A or 3B at Appendix A–2 to part 60 of this chapter, or ANSI/ ASME PTC 19.10–1981.3 Method 4 at Appendix A–3 to part 60 of this chapter. Method 5 at Appendix A–3 to part 60 of this chapter. For positive pressure fabric filters, Method 5D at Appendix A–3 to part 60 of this chapter for filterable PM emissions. Note that the Method 5 front half temperature shall be 160 ° ± 14 °C (320 ° ± 25 °F). Method 19 F-factor methodology at Appendix A–7 to part 60 of this chapter, or calculate using mass emissions rate and electrical output data (see § 63.10007(e)). Performance Specification 11 at Appendix B to part 60 of this chapter and Procedure 2 at Appendix F to Part 60 of this chapter. Part 75 of this chapter and §§ 63.10010(a), (b), (c), and (d). 204 VerDate Mar<15>2010 17:15 Sep 14, 2012 Jkt 226160 PO 00000 Addendum – 056 Fmt 8010 Sfmt 8002 Q:\40\40V15.TXT Frm 00214 ofr150 PsN: PC150 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 1 of 105 ORAL ARGUMENT NOT YET SCHEDULED No. 16-1127 (and consolidated cases) ______________________________________ IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT _______________________________________ MURRAY ENERGY CORPORATION, et al., Petitioners, V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, et al., Respondents. ______________________________________ On Petitions for Review of Final Agency Action of the United States Environmental Protection Agency 81 Fed. Reg. 24,420 (Apr. 25, 2016) ______________________________________ OPENING BRIEF OF STATE AND INDUSTRY PETITIONERS ______________________________________ F. William Brownell Makram B. Jaber Andrew D. Knudsen HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 Fax: (202) 778-2201 bbrownell@hunton.com mjaber@hunton.com aknudsen@hunton.com Counsel for Petitioner Utility Air Regulatory Group DATED: November 18, 2016 Bill Schuette ATTORNEY GENERAL FOR THE PEOPLE OF MICHIGAN Aaron D. Lindstrom, Solicitor General Neil D. Gordon Brian J. Negele Assistant Attorneys General ENRA Division 525 W. Ottawa Street P.O. Box 30755 Lansing, MI 48909 Tel: (515) 373-7540 Fax: (517) 373-1610 gordonn1@michigan.gov negeleb@michigan.gov Counsel for Petitioner Michigan Attorney General Bill Schuette, on behalf of the People of Michigan Additional counsel listed on following pages USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 2 of 105 Geoffrey K. Barnes J. Van Carson Wendlene M. Lavey John D. Lazzaretti Robert D. Cheren SQUIRE PATTON BOGGS (US) LLP 4900 Key Tower 127 Public Square Cleveland, OH 44114 Tel: (216) 479-8646 geoffrey.barnes@squirepb.com Luther Strange ATTORNEY GENERAL OF ALABAMA Robert D. Tambling State of Alabama Office of the Attorney General 501 Washington Avenue Montgomery, AL 36130 Tel: (334) 242-7445 Fax: (334) 242-2433 Counsel for Petitioner Murray Energy Corporation Mark Brnovich ATTORNEY GENERAL OF ARIZONA John R. Lopez IV Solicitor General Keith J. Miller Assistant Solicitor General James T. Skardon Assistant Attorney General 1275 West Washington Street Phoenix, AZ 85007 Tel: (602) 542-3333 keith.miller@azag.gov Bart E. Cassidy Katherine L. Vaccaro MANKO, GOLD, KATCHER & FOX, LLP 401 City Avenue, Suite 901 Bala Cynwyd, PA 19004 Tel: (484) 430-5700 bcassidy@mankogold.com kvaccaro@mankogold.com Counsel for Petitioner State of Alabama Counsel for Petitioner ARIPPA Counsel for Petitioner State of Arizona Stacey Turner SOUTHERN COMPANY SERVICES, INC. 600 18th Street North BIN 14N-8195 Birmingham, AL 35203 Tel: (205) 257-2823 staturne@southernco.com Counsel for Petitioner Southern Company Services, Inc. Leslie Rutledge ATTORNEY GENERAL OF ARKANSAS Lee Rudofsky Solicitor General Nicholas J. Bronni Deputy Solicitor General Office of the Attorney General 323 Center Street, Suite 200 Little Rock, AR 72201 Tel: (501) 682-8090 Counsel for Petitioner State of Arkansas USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 3 of 105 C. Grady Moore, III BALCH & BINGHAM LLP 1901 Sixth Avenue North, Suite 1500 Birmingham, AL 35303-4642 Tel: (205) 226-8718 Fax: (205) 488-5704 gmoore@balch.com Derek Schmidt ATTORNEY GENERAL OF KANSAS Jeffrey A. Chanay Chief Deputy Attorney General Office of the Attorney General 120 S.W. 10th Avenue, 3rd Floor Topeka, KS 66612-1597 Tel: (785) 368-8435 Counsel for Petitioner Alabama Power Company jeff.chanay@ag.ks.gov Angela J. Levin TROUTMAN SANDERS LLP 580 California Street, Suite 1100 San Francisco, CA 94104 Tel: (415) 477-5787 Fax: (415) 477-5710 angela.levin@troutmansanders.com Counsel for Petitioner State of Kansas Counsel for Petitioners Georgia Power Company and Southern Company Services, Inc. Counsel for Petitioner Commonwealth of Kentucky Terese T. Wyly BALCH & BINGHAM LLP 1310 Twenty Fifth Avenue Gulfport, MS 39501-1931 Tel: (228) 214-0413 Fax: (888) 897-6221 twyly@balch.com Douglas J. Peterson ATTORNEY GENERAL OF NEBRASKA Dave Bydalek Chief Deputy Attorney General Justin D. Lavene Assistant Attorney General 2115 State Capitol Lincoln, NE 68509 Tel: (402) 471-2682 justin.lavene@nebraska.gov Andy Beshear ATTORNEY GENERAL OF KENTUCKY Mitchel T. Denham Assistant Deputy Attorney General Joseph A. Newberg, II Assistant Attorney General Kentucky Office of the Attorney General Margaret Claiborne Campbell The Capitol Building TROUTMAN SANDERS LLP 600 Peachtree Street, NE, Suite 5200 700 Capitol Avenue, Suite 118 Atlanta, GA 30308-2216 Frankfort, KY 40601 Tel: (404) 885-3000 Tel: (502) 696-5300 Fax: (404) 962-6521 mitchel.denham@ky.gov margaret.campbell@troutmansanders.com joe.newberg@ky.gov Counsel for Petitioner Mississippi Power Company Counsel for Petitioner State of Nebraska USCA Case #16-1127 Document #1647029 Jeffrey A. Stone BEGGS & LANE, RLLP 501 Commendencia Street Pensacola, FL 32502 Tel: (850) 432-2451 JAS@beggslane.com Robert A Manning Joseph A. Brown HOPPING GREEN & SAMS, P.A. 119 S. Monroe Street, Suite 300 Tallahassee, FL 32301 Tel: (850) 222-7500 Fax: (850) 224-8551 robertm@hgslaw.com josephb@hgslaw.com Counsel for Petitioner Gulf Power Company Filed: 11/18/2016 Page 4 of 105 Wayne Stenehjem ATTORNEY GENERAL OF NORTH DAKOTA Margaret Olson Assistant Attorney General North Dakota Attorney General’s Office 500 North 9th Street Bismarck, ND 58501-4509 Tel: (701) 328-3640 Fax: (701) 328-4300 maiolson@nd.gov Counsel for Petitioner State of North Dakota Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ohioattorneygeneral.gov Counsel for Petitioner State of Ohio E. Scott Pruitt ATTORNEY GENERAL OF OKLAHOMA P. Clayton Eubanks Deputy Solicitor General 313 N.E. 21st Street Oklahoma City, OK 73105 Tel: (405) 522-8992 Fax: (405) 522-0085 clayton.eubanks@oag.ok.gov fc.docket@oag.state.ok.us Counsel for Petitioner State of Oklahoma USCA Case #16-1127 Document #1647029 P. Stephen Gidiere III C. Grady Moore, III Julia B. Barber BALCH & BINGHAM LLP 1901 6th Ave. N., Suite 1500 Birmingham, AL 35203 Tel: (205) 251-8100 sgidiere@balch.com Stephanie Z. Moore Executive Vice President & General Counsel VISTRA ENERGY CORP. 1601 Bryan Street, 22nd Floor Dallas, TX 75201 Daniel J. Kelly Vice President and Associate General Counsel VISTRA ENERGY CORP. 1601 Bryan Street, 43rd Floor Dallas, TX 75201 Counsel for Petitioner Oak Grove Management Company LLC Filed: 11/18/2016 Page 5 of 105 Alan Wilson ATTORNEY GENERAL OF SOUTH CAROLINA James Emory Smith, Jr. Deputy Solicitor General Office of the Attorney General P.O. Box 11549 Columbia, SC 29211 Tel: (803) 734-3680 esmith@scag.gov Counsel for Petitioner State of South Carolina Ken Paxton ATTORNEY GENERAL OF TEXAS Jeffrey C. Mateer First Assistant Attorney General Brantley Starr Deputy First Assistant Attorney General James E. Davis Deputy Attorney General for Civil Litigation Priscilla M. Hubenak Chief, Environmental Protection Division Mary E. Smith Assistant Attorney General Office of the Attorney General of Texas Environmental Protection Division P.O. Box 12548, MC-066 Austin, TX 78711-2548 Tel: (512) 475-4041 Fax: (512) 320-0911 mary.smith@texasattorneygeneral.gov Counsel for Petitioners State of Texas, Texas Commission on Environmental Quality, Public Utility Commission of Texas, and Railroad Commission of Texas USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 6 of 105 Patrick Morrisey ATTORNEY GENERAL OF WEST VIRGINIA Elbert Lin Solicitor General Counsel of Record State Capitol Building 1, Room 26-E Charleston, WV 25305 Tel: (304) 558-2021 Fax: (304) 558-0140 elbert.lin@wvago.gov Counsel for Petitioner State of West Virginia Brad D. Schimel ATTORNEY GENERAL OF WISCONSIN Misha Tseytlin Solicitor General Counsel of Record Wisconsin Department of Justice 17 West Main Street Madison, WI 53707 Tel: (608) 267-9323 tseytlinm@doj.state.wi.us Counsel for Petitioner State of Wisconsin USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 7 of 105 Peter K. Michael ATTORNEY GENERAL OF WYOMING James Kaste Deputy Attorney General Michael J. McGrady Senior Assistant Attorney General Elizabeth A. Morrisseau Assistant Attorney General Wyoming Attorney General’s Office 2320 Capitol Avenue Cheyenne, WY 82002 Tel: (307) 777-6946 Fax: (307) 777-3542 james.kaste@wyo.gov mike.mcgrady@wyo.gov elizabeth.morrisseau@wyo.gov Counsel for Petitioner State of Wyoming USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 8 of 105 CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES Pursuant to Circuit Rule 28(a)(1), Petitioners state as follows: A. Parties, Intervenors, and Amici Curiae These cases involve the following parties: Petitioners: No. 16-1127: Murray Energy Corporation. No. 16-1175: ARIPPA. No. 16-1204: Michigan Attorney General Bill Schuette, on behalf of the People of Michigan; State of Alabama; State of Arizona; State of Arkansas; State of Kansas; Commonwealth of Kentucky; State of Nebraska; State of North Dakota; State of Ohio; State of Oklahoma; State of South Carolina; State of Texas; State of West Virginia; State of Wisconsin; State of Wyoming; Texas Commission on Environmental Quality; Public Utility Commission of Texas; and Railroad Commission of Texas. No. 16-1206: Oak Grove Management Company LLC. No. 16-1208: Southern Company Services, Inc.; Alabama Power Company; Georgia Power Company; Gulf Power Company; and Mississippi Power Company. No. 16-1210: Utility Air Regulatory Group. i USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 9 of 105 Respondents: Respondents are the United States Environmental Protection Agency (in Nos. 16-1175, 16-1204, 16-1208, and 16-1210) and the United States Environmental Protection Agency and Gina McCarthy, Administrator (in Nos. 16-1127 and 16-1206). Intervenors and Amici Curiae: Conservation Law Foundation; Environmental Defense Fund; Natural Resources Council of Maine; The Ohio Environmental Council; Sierra Club; Commonwealth of Massachusetts; Commonwealth of Virginia; State of California; State of Connecticut; State of Delaware; State of Iowa; State of Illinois; State of Maine; State of Maryland; State of Minnesota; State of New Hampshire; State of New Mexico; State of New York; State of Oregon; State of Rhode Island; State of Vermont; Washington, the District of Columbia; City of Baltimore; City of Chicago; City of New York; County of Erie, New York; American Lung Association; American Public Health Association; Chesapeake Bay Foundation; Chesapeake Climate Action Network; Citizens for Pennsylvania’s Future; Clean Air Council; Downwinders at Risk; Environmental Integrity Project; National Association for the Advancement of Colored People; Natural Resources Defense Council; Physicians for Social Responsibility; Calpine Corporation; and Exelon Corporation are Intervenors in support of Respondents. There are no Intervenors in support of Petitioners. ii USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 10 of 105 The Institute for Policy Integrity at New York University School of Law is amicus curiae in support of Respondents. There are no amicus curiae in support of Petitioners. B. Rulings Under Review These consolidated cases involve final agency action of the United States Environmental Protection Agency titled, “Supplemental Finding That It Is Appropriate and Necessary to Regulate Hazardous Air Pollutants from Coal- and OilFired Electric Utility Steam Generating Units,” and published on April 25, 2016, at 81 Fed. Reg. 24,420. C. Related Cases These consolidated cases have not previously been before this Court or any other court. Counsel is aware of the following related case that, as of the time of filing, has appeared before this Court: (1) White Stallion Energy Center, LLC v. EPA, 748 F.3d 1222 (D.C. Cir. 2014), rev’d, Michigan v. EPA, 135 S. Ct. 2699 (2015) (No. 12-1100 and consolidated Nos. 121101, 12-1102, 12-1147, 12-1170, 12-1172, 12-1173, 12-1174, 12-1175, 12-1176, 121177, 12-1178, 12-1180, 12-1181, 12-1182, 12-1183, 12-1184, 12-1185, 12-1186, 121187, 12-1188, 12-1189, 12-1190, 12-1191, 12-1192, 12-1193, 12-1194, 12-1195, 121196). Counsel is aware of the following related case that, as of the time of filing, is currently before this Court: iii USCA Case #16-1127 (1) Document #1647029 Filed: 11/18/2016 Page 11 of 105 ARIPPA v. EPA, No. 15-1180 (and consolidated Nos. 15-1191 and 15- 1192) regarding EPA’s “Reconsideration on the Mercury and Air Toxics Standards (MATS) and the Utility New Source Performance Standards; Notice of Final Action Denying Petitions for Reconsideration,” 80 Fed. Reg. 24,218 (Apr. 30, 2015). Recognizing the relationship between the instant case and ARIPPA, this Court has ordered that the two cases be scheduled for argument on the same day and before the same panel. Order at 2, ARIPPA v. EPA, No. 15-1180, and Murray Energy Corp. v. EPA, No. 16-1127 (D.C. Cir. Aug. 29, 2016), ECF No. 1632520. Counsel is aware of the following related cases that, as of the time of filing, have appeared before the United States Supreme Court: (1) Michigan v. EPA, 135 S. Ct. 2699 (2015) (No. 14-46). (2) Utility Air Regulatory Grp. v. EPA, 135 S. Ct. 2699 (2015) (No. 14-47, consolidated with No. 14-46). (3) Nat’l Mining Ass’n v. EPA, 135 S. St. 2699 (2015) (No. 14-49, consolidated with No. 14-46). iv USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 12 of 105 CORPORATE DISCLOSURE STATEMENTS Non-governmental Petitioners submit the following statements pursuant to Rule 26.1 of the Federal Rules of Appellate Procedure and Circuit Rule 26.1: Alabama Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Alabama Power Company’s stock. No publicly-held company holds 10% or more of Southern Company’s stock. Southern Company stock is traded publicly on the New York Stock Exchange under the symbol “SO.” ARIPPA is a non-profit trade association that represents a membership primarily comprised of electric generating plants using environmentally-friendly circulating fluidized bed boiler technology to convert coal refuse and/or other alternative fuels such as biomass into alternative energy and/or steam, with the resultant alkaline ash used to reclaim mine lands. ARIPPA was organized in 1988 for the purpose of promoting the professional, legislative and technical interests of its member facilities. ARIPPA has no outstanding shares or debt securities in the hands of the public and does not have any parent, subsidiary, or affiliate that has issued shares or debt securities to the public. Georgia Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Georgia Power Company’s stock. No publicly-held company holds 10% or more of Southern Company’s stock. Southern Company stock is traded publicly on the New York Stock Exchange under the symbol “SO.” Gulf Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Gulf Power Company’s stock. No publicly-held company holds 10% or more of Southern Company’s stock. Southern Company stock is traded publicly on the New York Stock Exchange under the symbol “SO.” Mississippi Power Company is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Mississippi Power Company’s stock. No publicly-held company holds 10% or more of Southern Company’s stock. Southern Company stock is traded publicly on the New York Stock Exchange under the symbol “SO.” Murray Energy Corporation has no parent corporation and no publicly held corporation owns ten percent (10%) or more of its stock. Murray Energy Corporation v USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 13 of 105 is the largest privately-held coal company and the largest underground coal mine operator in the United States, with combined operations that currently produce and ship about eighty-seven (87) million tons of bituminous coal annually. Oak Grove Management Company, LLC is a wholly owned subsidiary of Vistra Asset Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Vistra Operations Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Vistra Intermediate Company LLC, which is a Delaware limited liability company and is a wholly owned subsidiary of Vistra Energy Corp., which is a publicly held corporation. Vistra Energy Corp. is traded publicly on the OTCQX market under the symbol “VSTE.” Apollo Management Holdings L.P., Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P., and Oaktree Capital Management, L.P. are publicly held entities and each have subsidiaries that own more than 10% of Vistra Energy Corp.’s stock. Southern Company Services, Inc. is a wholly-owned subsidiary of Southern Company, which is a publicly held corporation. Other than Southern Company, no publicly-held company owns 10% or more of Southern Company Services, Inc.’s stock. No publicly-held company holds 10% or more of Southern Company’s stock. Southern Company stock is traded publicly on the New York Stock Exchange under the symbol “SO.” Utility Air Regulatory Group (“UARG”) is a not-for-profit association of individual electric generating companies and national trade associations. UARG participates on behalf of certain of its members collectively in Clean Air Act administrative proceedings that affect electric generators and in litigation arising from those proceedings. UARG has no outstanding shares or debt securities in the hands of the public and has no parent company. No publicly held company has a 10% or greater ownership interest in UARG. vi USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 14 of 105 TABLE OF CONTENTS Page CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES .................. i CORPORATE DISCLOSURE STATEMENTS ............................................................... v TABLE OF CONTENTS ..................................................................................................... vii TABLE OF AUTHORITIES ................................................................................................. x GLOSSARY OF TERMS .................................................................................................... xvii JURISDICTIONAL STATEMENT ..................................................................................... 1 STATEMENT OF ISSUES .................................................................................................... 1 STATUTES AND REGULATIONS ................................................................................... 2 INTRODUCTION .................................................................................................................. 2 STATEMENT OF THE CASE ............................................................................................. 4 I. The Clean Air Act’s Regulation of HAPs .................................................................. 4 A. Section 112 Program Prior to 1990................................................................. 4 B. Section 112 Program After the 1990 CAA Amendments ........................... 5 II. EPA’s § 112 Rulemakings for EGU HAPs ............................................................... 8 III. Michigan v. EPA ............................................................................................................ 17 IV. The Supplemental Finding ......................................................................................... 19 SUMMARY OF ARGUMENT ............................................................................................ 24 STANDING ............................................................................................................................ 26 STANDARD OF REVIEW ................................................................................................. 27 ARGUMENT .......................................................................................................................... 28 I. EPA’s “Affordability” Analysis Does Not Satisfy Its Obligation To Determine Whether the Benefits of Regulating EGUs Under § 112 Are Worth the Costs. .......................................................................................................... 28 vii USCA Case #16-1127 II. Document #1647029 Filed: 11/18/2016 Page 15 of 105 A. EPA Must Consider Costs in Relation to Benefits To Justify its “Appropriate and Necessary” Determination. ............................................ 29 B. EPA’s “Preferred Approach” Ignores Michigan and the Statute. .............. 33 1. EPA Unlawfully Failed To Weigh Costs Against Benefits. ........... 33 2. EPA Errs By Interpreting § 112(n)(1)(A) Not To Require Any Comparison of Costs and Benefits. .......................................... 37 3. EPA Unlawfully Fails To Assess the Costs and Benefits of Each of the Three, Multi-Billion Dollar Control Mandates. ......... 40 EPA’s “Alternative” Benefit-Cost Approach Is Also Invalid Because It Is Based on the “Co-Benefits” of Reducing Pollutants Other than HAPs. ....... 41 A. B. C. Congress Did Not Authorize EPA To Regulate EGU HAP Emissions Under § 112 Based on Reductions in Pollutants Regulated Under Other CAA Programs. ..................................................... 42 1. Section 112(n)(1)(A) Limits EPA’s Consideration to Whether the Benefits of Reducing HAPs Are Worth the Costs. ...................................................................................................... 43 2. Predicating § 112 Regulation of EGU HAP Emissions on PM2.5 Co-Benefits Resulting from SO2 Reductions Is an End-Run Around CAA Programs That Already Regulate These Non-HAPs. ............................................................................... 47 EPA’s Arguments for Relying on Co-Benefits Are Unavailing. ............... 49 1. EPA’s Invocation of General “Economic Principles” Is Irrelevant. .............................................................................................. 49 2. EPA’s Justification for Considering Co-Benefits Relies on a Logical Fallacy. ..................................................................................... 50 3. EPA Relies on the Illusory Co-Benefits of Reducing PM2.5 Below Levels That the Agency Has Already Found Protect the Public Health. ................................................................................. 51 EPA’s Vague Reference to Unquantifiable Benefits Does Not Support Its “Appropriate and Necessary” Finding. ................................... 55 viii USCA Case #16-1127 III. Document #1647029 Filed: 11/18/2016 Page 16 of 105 EPA’s Refusal To Consider Alternative Control Strategies and All Relevant Costs, Is Contrary to the Statute and the Supreme Court’s Direction. ...................................................................................................................... 58 A. EPA Impermissibly Ignores Less Costly Alternative Control Strategies for Reducing Emissions from EGUs. ........................................ 58 B. EPA Cannot Find § 112 “Appropriate” for EGUs Without Considering all Costs, Including Important Disadvantages and Localized Impacts. ........................................................................................... 63 CONCLUSION ...................................................................................................................... 71 CERTIFICATE OF COMPLIANCE CERTIFICATE OF SERVICE ix USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 17 of 105 TABLE OF AUTHORITIES FEDERAL CASES Page Am. Lung Ass’n v. EPA, 134 F.3d 388 (D.C. Cir. 1998) .................................................... 52 Am. Petroleum Inst. v. EPA, 52 F.3d 1113 (D.C. Cir. 1995) .................................. 45, 46, 47 Bond v. United States, 134 S. Ct. 2077 (2014)......................................................................... 62 Burlington Truck Lines v. United States, 371 U.S. 156 (1962) ................................................ 54 Entergy Corp. v. Riverkeeper, Inc., 556 U.S. 208 (2009) ................................................... 30, 31 Ethyl Corp. v. EPA, 51 F.3d 1053 (D.C. Cir. 1995) ............................................................ 45 FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009) ..................................................... 54 Indus. Union Dep’t, AFL-CIO v. Am. Petroleum Inst., 448 U.S. 607 (1980) ........... 31, 35, 39 Int’l Ladies’ Garment Workers’ Union v. Donovan, 722 F.2d 795 (D.C. Cir. 1983) ....................................................................................................................... 62, 63 Lead Indus. Ass’n v. EPA, 647 F.2d 1130 (D.C. Cir. 1980) ......................................... 52, 53 Lujan v. Defenders of Wildlife, 504 U.S. 555 (1992) ......................................................... 26, 27 *Michigan v. EPA, 135 S. Ct. 2699 (2015) .................. 1, 2, 3, 18, 22, 24, 25, 26, 28, 29, 30 .............................................................................. 31, 32, 35, 36, 37, 38, 39, 41, 43, 44 .............................................................................. 45, 55, 56, 57, 58, 59, 62, 63, 64, 68 Mingo Logan Coal Co. v. EPA, 829 F.3d 710 (D.C. Cir. 2016) .................................... 26, 64 Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29 (1983) ...................................................................................... 28, 42, 46, 54, 63, 67, 68 New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008) ..................................................... 4, 5, 13 _____________________ * Authorities upon which we chiefly rely are marked with asterisks. x USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 18 of 105 NRDC v. EPA, 529 F.3d 1077 (D.C. Cir. 2008) ................................................................ 15 Pillai v. Civil Aeronautics Bd., 485 F.2d 1018 (D.C. Cir. 1973) ............................................ 63 Texas v. EPA, 829 F.3d 405 (5th Cir. 2016) ........................................................................ 68 White Stallion Energy Ctr., LLC v. EPA, 748 F.3d 1222 (D.C. Cir. 2014) ........................ 17 White Stallion Energy Ctr., LLC v. EPA, No. 12-1100, 2015 WL 11051103 (D.C. Cir. Dec. 15, 2015)............................................................................................ 19 Whitman v. Am. Trucking Ass’ns, Inc., 531 U.S. 457 (2001) .................................... 44, 45, 52 FEDERAL STATUTES 2 U.S.C. § 1535 ........................................................................................................................ 63 5 U.S.C. § 602(c) ...................................................................................................................... 63 5 U.S.C. § 706 .......................................................................................................................... 27 Clean Air Act § 112, 42 U.S.C. § 1857c-7(a)(1) (1970) ........................................................ 4 Clean Air Act § 112, 42 U.S.C. § 1857c-7(b)(1)(B) (1970) .................................................. 4 Clean Air Act, 42 U.S.C. §§ 7401, et seq. (2015) CAA § 102(a), 42 U.S.C. § 7402(a) ........................................................................... 61 CAA § 108, 42 U.S.C. § 7408 .................................................................................... 45 CAA § 109, 42 U.S.C. § 7409 .................................................................................... 45 CAA § 109(b), 42 U.S.C. § 7409(b) ................................................................... 44, 52 CAA § 109(b)(1), 42 U.S.C. § 7409(b)(1) ................................................................. 52 CAA § 109(b)(2), 42 U.S.C. § 7409(b)(2) ................................................................. 52 CAA § 109(d)(1), 42 U.S.C. § 7409(d)(1) ................................................................... 5 xi USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 19 of 105 CAA § 111(d), 42 U.S.C. § 7411(d).............................................................. 26, 60, 61 CAA § 112, 42 U.S.C. § 7412 ...................................................................................... 4 CAA § 112(a)(1), 42 U.S.C. § 7412(a)(1) .................................................................... 5 CAA § 112(b), 42 U.S.C. § 7412(b) ............................................................................ 3 CAA § 112(b)(1), 42 U.S.C. § 7412(b)(1) ................................................................... 5 CAA § 112(c), 42 U.S.C. § 7412(c) ........................................................................... 12 CAA § 112(c)(9), 42 U.S.C. § 7412(c)(9) .................................................................. 13 CAA § 112(d), 42 U.S.C. § 7412(d)...................................................................... 6, 30 CAA § 112(d)(2), 42 U.S.C. § 7412(d)(2) ................................................................... 6 CAA § 112(d)(3), 42 U.S.C. § 7412(d)(3) ............................................................ 6, 58 CAA § 112(d)(3)(A), 42 U.S.C. § 7412(d)(3)(A) ..................................................... 58 CAA § 112(f), 42 U.S.C. § 7412(f) ....................................................................... 6, 64 CAA § 112(k)(4), 42 U.S.C. § 7412(k)(4) ................................................................. 61 CAA § 112(l)(3), 42 U.S.C. § 7412(l)(3) ................................................................... 61 CAA § 112(n)(1)(A), 42 U.S.C. § 7412(n)(1)(A) ............................... 7, 8, 32, 33, 40 ........................................................................................................41, 43, 45, 50, 58, 61 CAA § 112(n)(1)(B), 42 U.S.C. § 7412(n)(1)(B) ........................................... 8, 33, 44 CAA § 112(n)(1)(C), 42 U.S.C. § 7412(n)(1)(C) ...................................................... 44 CAA § 116, 42 U.S.C. § 7416 ............................................................................. 23, 61 CAA § 211(k), 42 U.S.C. § 7545(k) ........................................................................... 46 CAA § 302(h), 42 U.S.C. § 7602(h) .......................................................................... 52 xii USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 20 of 105 CAA § 307(b)(1), 42 U.S.C. § 7607(b)(1) ................................................................... 1 CAA § 307(d)(9), 42 U.S.C. § 7607(d)(9) ................................................................. 27 CAA §§ 401 et seq., 42 U.S.C. §§ 7651 et seq. ............................................................ 43 CAA § 401(b), 42 U.S.C. § 7651(b) .......................................................................... 48 LEGISLATIVE HISTORY 136 CONG. REC. 3493 (Mar. 6, 1990) .............................................................................. 6, 32 136 CONG. REC. 35,013 (Oct. 26, 1990) ....................................................................... 48, 59 136 CONG. REC. 35,075 (Oct. 26, 1990) .............................................................................. 32 Energy Policy Implications of the Clean Air Act Amendments of 1989: Hearing Before the S. Comm. on Energy & Natural Resources, 101st Cong. (1990) (testimony of William G. Rosenberg, Assistant Adm’r, Air & Radiation, EPA) ................................................................................................. 7, 32 H.R. 3030, 101st Cong. (1989) (as introduced) .................................................................... 8 Pub. L. No. 91-604, 84 Stat. 1676 (1970) .............................................................................. 4 Pub. L. No. 101-549, 104 Stat. 2399 (1990) ......................................................................7, 8 S. 1490, 101st Cong. (1989) (as introduced) ......................................................................... 8 S. Rep. No. 101-228 (1989), reprinted in 1990 U.S.C.C.A.N. 3385 ..................................... 5 The American Energy Initiative, Part 15: What EPA’s Utility MACT Rule Will Cost U.S. Consumers: Hearing Before the Subcomm. on Energy & Power of the H. Comm. on Energy & Commerce, 112th Cong. (2012) (statement of Anne E. Smith, Ph.D.) ....................................................................... 16 FEDERAL REGULATIONS 40 C.F.R. § 50.13 ..................................................................................................................... 52 40 C.F.R. § 50.18 ..................................................................................................................... 52 xiii USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 21 of 105 40 C.F.R. pt. 60, subpt. B ....................................................................................................... 23 40 C.F.R. § 60.24(f) ................................................................................................................. 60 FEDERAL REGISTER 40 Fed. Reg. 48,292 (Oct. 14, 1975) ....................................................................................... 4 52 Fed. Reg. 8724 (Mar. 19, 1987) .......................................................................................... 5 54 Fed. Reg. 38,044 (Sept. 14, 1989) ...................................................................................... 4 54 Fed. Reg. 51,654 (Dec. 15, 1989) ...................................................................................... 5 63 Fed. Reg. 64,632 (Nov. 23, 1998) .................................................................................... 27 65 Fed. Reg. 79,825 (Dec. 20, 2000) .................................................................................... 11 69 Fed. Reg. 4652 (Jan. 30, 2004) .................................................................................. 11, 60 70 Fed. Reg. 15,994 (Mar. 29, 2005)....................................................................9, 11, 12, 43 70 Fed. Reg. 28,606 (May 18, 2005) ..................................................................................... 12 71 Fed. Reg. 33,388 (June 9, 2006) ....................................................................................... 12 76 Fed. Reg. 24,976 (May 3, 2011) ..................................... 9, 13, 14, 15, 39, 40, 56, 62, 69 77 Fed. Reg. 9304 (Feb. 16, 2012) ........................................................13, 14, 15, 16, 17, 36 78 Fed. Reg. 3086 (Jan. 15, 2013) ............................................................................ 51, 52, 53 80 Fed. Reg. 75,025 (Dec. 1, 2015)................ 19, 20, 21, 28, 29, 34, 35, 37, 55, 56, 57, 67 81 Fed. Reg. 22,977 (Apr. 19, 2016) ..................................................................................... 55 81 Fed. Reg. 24,420 (Apr. 25, 2016) .......................1, 19, 20, 21, 22, 23, 34, 35, 36, 37, 39 ................................................................. 40, 41, 44, 49, 50, 56, 59, 62, 64, 67, 68, 70 xiv USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 22 of 105 CASE MATERIALS Br. for the Fed. Resp’ts in Opp’n, Michigan v. EPA, 135 S. Ct. 2699 (2015) (No. 14-46) ....................................................................................................... 15 Final Br. of Resp’t EPA, New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008) (No. 05-1097) .................................................................................................... 12 Order, ARIPPA v. EPA, No. 15-1180, and Murray Energy Corp. v. EPA, No. 16-1127 (D.C. Cir. Aug. 29, 2016), ECF No. 1632520 ................................. 14 Tr. of Oral Arg., Michigan v. EPA, 135 S. Ct. 2699 (2015) (No. 14-46) .......................... 47 MISCELLANEOUS Dockter, Warren, How to drink like Winston Churchill, THE TELEGRAPH (Jan. 28, 2015), http://www.telegraph.co.uk/news/winstonchurchill/11374144/How-to-drink-like-Winston-Churchill.html ....................... 34 EPA, Air Pollution Control Technology Fact Sheet; Dry Electrostatic Precipitator (ESP) – Wire-Plate Type, EPA-452/F-03-028 (undated) ....................................................................................................................... 10 EPA, Guidelines for Preparing Economic Analyses (Dec. 17, 2010, updated May 2014), https://www.epa.gov/environmentaleconomics/guidelines-preparing-economic-analyses ............................................ 49 EPA, Mercury Study Report to Congress, Vol. 1, EPA-452/R-97-003 (Dec. 1997), EPA-HQ-OAR-2009-0234-3054 ......................................................... 9 EPA, Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards, EPA-452/R-11-011 (Dec. 2011), EPA-HQ-OAR2009-0234-20131 .................................................................. 16, 17, 22, 51, 54, 55, 57 EPA, Response to Comments for Supplemental Finding that it is Appropriate and Necessary to Regulate Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units (Apr. 2016), EPA-HQ-OAR-2009-0234-20578 .............. 23, 40, 64, 65, 66, 67, 68 xv USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 23 of 105 EPA, Revised Technical Support Document: National-Scale Assessment of Mercury Risk to Populations with High Consumption of Self-caught Freshwater Fish In Support of the Appropriate and Necessary Finding for Coal- and Oil-Fired Electric Generating Units, EPA-452/R-11-009 (Dec. 2011), EPAHQ-OAR-2009-0234-19913 ...................................................................................... 14 EPA, Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units, Final Report to Congress, Vol. 1, EPA453/R-98-004a (Feb. 1998), EPA-HQ-OAR-2009-0234-3052 ................................................ 9, 10, 13, 14, 15, 17 EPA, The Benefits and Costs of the Clean Air Act, 1970 to 1990 (Oct. 1997), https://www.epa.gov/clean-air-act-overview/benefits-andcosts-clean-air-act-1970-1990-retrospective-study ................................................... 5 EPA, The Benefits and Costs of the Clean Air Act 1990 to 2010, EPA410-R-99-001 (Nov. 1999), https://www.epa.gov/sites/production/files/201507/documents/fullrept.pdf........................................................................................ 16 Legal Memorandum Accompanying the Proposed Supplemental Finding that it is Appropriate and Necessary to Regulate Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units (EGUs) (undated), EPA-HQ-OAR-2009-023420519 ...................................................................................... 20, 28, 33, 34, 35, 37, 38 National Acid Precipitation Assessment Program, National Acid Precipitation Assessment Program Report to Congress 2011: An Integrated Assessment (Dec. 2011), www.whitehouse.gov/sites/default/files/microsites/ostp/2011_n apap_508.pdf .................................................................................................................. 6 Reilly, William K., Adm’r, EPA, Letter to Members of the Senate (Jan. 26, 1990)............................................................................................................... 7, 8, 60 U.S. Energy Information Administration, Today in Energy: EIA electricity generator data show power industry response to EPA mercury limits (July 7, 2016), http://www.eia.gov/todayinenergy/detail.php?id=26972 ................................... 66 xvi USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 24 of 105 GLOSSARY OF TERMS Act (or CAA) Clean Air Act EGU Electric Generating Unit EPA (or Agency) United States Environmental Protection Agency GW Gigawatts HAP Hazardous Air Pollutant JA Joint Appendix MATS Mercury and Air Toxics Standards, 77 Fed. Reg. 9304 (Feb. 16, 2012) NAAQS National Ambient Air Quality Standards PM2.5 Fine Particulate Matter RIA Regulatory Impact Analysis Rule Supplemental Finding That It Is Appropriate and Necessary To Regulate Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units; Final Rule, 81 Fed. Reg. 24,420 (Apr. 25, 2016) SO2 Sulfur Dioxide UARG Utility Air Regulatory Group xvii USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 25 of 105 JURISDICTIONAL STATEMENT These consolidated cases challenge a final action of the U.S. Environmental Protection Agency (“EPA” or “Agency”) under the Clean Air Act (“CAA” or “Act”), published at 81 Fed. Reg. 24,420 (Apr. 25, 2016) (the “Rule”), Joint Appendix (“JA”) ___-___. This Court has jurisdiction under CAA § 307(b)(1).1 Petitions for review were timely filed. STATEMENT OF ISSUES The Supreme Court held in Michigan v. EPA, 135 S. Ct. 2699 (2015), that EPA must consider cost in determining whether it is “appropriate and necessary” to regulate emissions of hazardous air pollutants (“HAPs”) from electric generating units (“EGUs”) under § 112 of the Act. The Rule consists of EPA’s supplemental finding that such regulation is appropriate and necessary, notwithstanding estimated quantifiable annual costs of $9.6 billion and benefits of $4 to $6 million. 1. Whether EPA’s “preferred approach,” under which EPA finds that § 112 regulation is appropriate and necessary if it is affordable for the industry as a whole, is contrary to Michigan and § 112(n)(1)(A), and is otherwise arbitrary, capricious, or unlawful. 2. Whether EPA’s alternative “formal benefit-cost analysis,” which relies on the “co-benefits” of incidental reductions of non-HAPs to justify the $9.6 billion 1 The Table of Authorities provides parallel citations to the U.S. Code. USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 26 of 105 annual cost of regulating EGU HAPs under § 112, is contrary to Michigan and § 112(n)(1)(A), and is otherwise arbitrary, capricious, or unlawful. 3. Whether EPA’s refusal to consider alternative strategies in lieu of regulating EGUs under § 112 and to consider all relevant costs and disadvantages, is contrary to Michigan and § 112(n)(1)(A), and is otherwise arbitrary, capricious, or unlawful. STATUTES AND REGULATIONS This case involves EPA’s finding made pursuant to a claim of authority under CAA § 112(n)(1)(A). The addendum reproduces pertinent portions of cited statutes and regulations. INTRODUCTION There is no escaping these facts: the most expensive rulemaking in EPA’s history—costing at least $9.6 billion annually by EPA’s estimation—would result in a paltry $4 to $6 million in purported public health benefits from reducing the pollutants it aims to address. In its previous attempt to justify regulating EGUs under § 112, EPA sought to avoid these inconvenient facts by asserting that costs do not matter at all under § 112(n)(1)(A). The Supreme Court emphatically rejected EPA’s position, admonishing that “[o]ne would not say that it is even rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few dollars in health or environmental benefits.” Michigan, 135 S. Ct. at 2707. 2 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 27 of 105 Instead of developing a thoughtful comparison of costs and benefits on remand, EPA fell back on its prior determination of small, uncertain, and largely unquantifiable benefits associated with regulation of HAPs2 under § 112 and concluded those benefits are justified so long as the industry can afford to spend $9.6 billion on this regulation annually. But affordability cannot satisfy the Supreme Court’s direction that EPA weigh benefits and costs to ensure they are not disproportionate. Id. at 2707 (“No regulation is ‘appropriate’ if it does significantly more harm than good.”). In fact, EPA never examined whether the benefits of regulation under § 112 outweigh the substantial costs. EPA did not ask whether it is “even rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for” the particular benefits it identified. Id. And it did not ask whether $9.6 billion annual costs are “disproportionate to the[se particular] benefits.” Id. at 2710. EPA alternatively relies on the co-benefits of reducing a non-HAP—fine particulate matter (“PM2.5”), which in turn would result from mandating reductions in another non-HAP: sulfur dioxide (“SO2”)—to justify the costs of regulating EGU HAPs under § 112. But the benefit-cost analysis EPA cites, which was developed for the original rulemaking, shows unequivocally that the costs dwarf the benefits attributable to reducing the regulated pollutants (i.e., the HAPs). EPA cannot properly 2 In this brief, “HAPs” refers to substances listed under § 112(b). 3 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 28 of 105 conclude that it is “appropriate and necessary” to regulate HAPs under § 112 if virtually all the benefits of doing so derive from incidental reductions in non-HAPs that are regulated under numerous other CAA programs. STATEMENT OF THE CASE I. The Clean Air Act’s Regulation of HAPs A. Section 112 Program Prior to 1990 Prior to 1990, § 112 required EPA to identify hazardous substances for regulation and develop emission standards for each to provide an “ample margin of safety” to protect public health. Pub. L. No. 91-604, § 112, 84 Stat. 1676, 1685 (1970); 42 U.S.C. § 1857c-7(a)(1), (b)(1)(B) (1970). EPA interpreted the phrase “ample margin of safety” to authorize a risk management decision considering “all health information … as well as other relevant factors including costs and economic impacts, technological feasibility, and other factors relevant to each particular decision.” 54 Fed. Reg. 38,044, 38,045 (Sept. 14, 1989), JA___. EPA listed eight hazardous substances and regulated seven of them before 1990, for a limited number of source categories. See New Jersey v. EPA, 517 F.3d 574, 578 (D.C. Cir. 2008). In part because emissions of these substances comprise a minuscule percentage of overall EGU emissions, every EPA evaluation of EGUs before 1990 under the “ample margin of safety” standard concluded their hazardoussubstance emissions did not pose a significant public health risk. See, e.g., 40 Fed. Reg. 48,292, 48,297, 48,298 (Oct. 14, 1975) (examining EGU mercury emissions), JA___, 4 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 29 of 105 ___; 52 Fed. Reg. 8724, 8725 (Mar. 19, 1987) (same), JA___; 54 Fed. Reg. 51,654, 51,671-72 (Dec. 15, 1989) (radionuclides), JA___-___. Over this same period, other CAA programs required EGUs to install controls for a variety of conventional (non-hazardous) pollutants, including flue gas desulfurization systems (known as “scrubbers”) for SO2 emissions and fabric filters or electrostatic precipitators for particulate matter emissions. Hazardous substances emitted during EGU combustion were also “incident[ally]” reduced by these controls.3 B. Section 112 Program After the 1990 CAA Amendments In 1990, Congress amended the CAA to substantially broaden the scope of substances to be addressed under § 112 and also transformed § 112 from a strictly health-based program to a control technology-driven program. S. Rep. No. 101-228, at 131-33 (1989), reprinted in 1990 U.S.C.C.A.N. 3385, 3516-18, JA___-___; New Jersey, 517 F.3d at 578. Congress listed 189 HAPs, CAA § 112(b)(1), and required EPA to regulate any source category containing at least one source that emits more than either 10 tons per year of any one HAP or 25 tons per year of all HAPs, id. § 112(a)(1), (c)(1). 3 EPA, The Benefits and Costs of the Clean Air Act, 1970 to 1990, at 39 (Oct. 1997), https://www.epa.gov/clean-air-act-overview/benefits-and-costs-clean-air-act1970-1990-retrospective-study, JA___. 5 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 30 of 105 For listed categories, Congress directed EPA initially to promulgate “technology-based” emission standards under § 112(d), which are set at the levels of control achieved by the best performers in the category. Id. § 112(d)(2), (3). It directed EPA to later consider more stringent standards under § 112(f) if needed to protect public health with an “ample margin of safety.” Congress in 1990 also enacted significant additional requirements to reduce EGU emissions of conventional pollutants (i.e., non-HAPs), such as SO2, nitrogen oxides, and PM. These programs included the regional haze and acid rain programs, and imposed new criteria pollutant nonattainment requirements. These programs reduced EGU emissions of non-HAP, conventional pollutants by many millions of tons. The additional controls EGUs installed to comply with these programs also lowered EGU HAP emissions beyond already low, pre-1990 levels.4 Congress was concerned that regulating EGUs under § 112 also “would increase power rates, while potentially providing little or no public health benefit.” 136 CONG. REC. 3493 (Mar. 6, 1990) (statement of Sen. Steve Symms), JA___. Indeed, EPA reported to Congress that regulating EGUs under § 112 “may result in several billion dollars of unnecessary costs with unknown environmental benefits.” 4 See National Acid Precipitation Assessment Program, National Acid Precipitation Assessment Program Report to Congress 2011: An Integrated Assessment (Dec. 2011), www.whitehouse.gov/sites/default/files/microsites/ostp/ 2011_napap_508.pdf, JA___-___. 6 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 31 of 105 Letter from William K. Reilly, Adm’r, EPA, to Members of the Senate (Jan. 26, 1990) (“Administrator 1990 Letter to Senate”), JA___. The Agency also warned that doing so would cost “billions of dollars” and yield only “very marginal environmental benefit.”5 To address the fact that Congress adopted in 1990 in other parts of the Act several comprehensive new programs to reduce EGU emissions, and recognizing the cost-benefit imbalance of further constraining EGU HAP emissions, Congress enacted an EGU-specific regulatory threshold: § 112(n)(1). Pub. L. No. 101-549, 104 Stat. 2399, 2558-59 (1990), JA___-___. That provision instructs EPA to conduct “a study of the hazards to public health reasonably anticipated to occur as a result of [the EGU HAP] emissions” that remain “after imposition of the [other] requirements of this [Act].” CAA § 112(n)(1)(A) (emphasis added). As part of that evaluation (commonly known as the “Utility Study”), EPA must “develop and describe … alternative control strategies for [any HAP] emissions which may warrant regulation under this section.” Id. Then, for those HAP emissions that might “warrant” regulation, Congress authorized EPA to regulate them “under this section” only if it 5 Energy Policy Implications of the Clean Air Act Amendments of 1989: Hearing Before the S. Comm. on Energy & Natural Resources, 101st Cong. 241 (1990) (testimony of William G. Rosenberg, Assistant Adm’r, Air & Radiation, EPA) (“Energy Policy Hearing”), JA___; see also Comments of Murray Energy Corporation on EPA’s Proposed Supplemental Finding at 14-29 (Jan. 15, 2016), EPA-HQ-OAR-2009-023420536 (“Murray Comments”), JA___-___ (presenting extensive legislative history). 7 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 32 of 105 determines that “such regulation is appropriate and necessary after considering the results of the study.” Id. Congress also directed EPA to perform a study (commonly known as the “Mercury Study”) to evaluate the “rate and mass” of EGU mercury emissions, “the health and environmental effects of such emissions,” and the cost of available control technologies for mercury. Id. § 112(n)(1)(B). As a companion to § 112(n)(1), which required EPA to consider alternative control strategies, Congress agreed to the Administration’s proposal to provide one particular such alternative: flexible, cooperative state and federal regulation of existing EGU emissions under § 111(d). See H.R. 3030, 101st Cong. § 108(d) (1989) and S. 1490, 101st Cong. § 108(d) (1989) (as introduced), JA___, ___; Pub. L. No. 101-549, § 108(g), 104 Stat. 2399, 2467 (1990), JA___. EPA explained this proposal would “allow[] the needed flexibility to identify and address the most significant toxic chemicals from utilities without mandating expensive controls that may be unnecessary.” Administrator 1990 Letter to Senate, JA___. II. EPA’s § 112 Rulemakings for EGU HAPs Most HAP emissions from EGUs result from chemical elements that are naturally present in trace amounts in the fuels they burn. They include mercury, nonmercury metals (such as chromium), and acid gases (such as hydrogen chloride). The Mercury and Utility Studies − After the 1990 CAA Amendments, EPA began updating information on HAPs emitted by EGUs, and conducted modeling to determine how those emissions may affect public health. The results of these efforts 8 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 33 of 105 were reported in the December 1997 Mercury Study6 and the February 1998 Utility Study.7 EPA’s studies found EGU HAPs presented limited exposure to humans. In particular, humans are exposed to mercury chiefly through consuming fish containing methylmercury formed in the first instance by aquatic microbes. 76 Fed. Reg. 24,976, 24,983 (May 3, 2011), JA___; Comments of the Utility Air Regulatory Group on EPA’s Proposed Supplemental Finding at 10 (Jan. 15, 2016), EPA-HQ-OAR-20090234-20557 (“UARG Comments”), JA___. EPA found in 1998 that U.S. coal-fired EGUs emitted about 51.5 tons of mercury, or about 1 percent of the 5,000 tons of worldwide mercury emissions, Utility Study at 7-8, Tbl. 7-1, which by 2010 had fallen dramatically to 29 tons, 76 Fed. Reg. at 25,002, JA___. Of the nine tons of domestic EGU mercury emissions deposited in the U.S., a very small portion ends up as methylmercury in fish people eat, and consequently human exposure to methylmercury resulting from coal-fired EGUs is exceedingly small. UARG Comments at 10 (citing, e.g., 70 Fed. Reg. 15,994, 16,019-21 (Mar. 29, 2005)), JA___. Likewise, trace amounts of non-mercury metals, naturally present in coal and oil, adhere to particulate ash, virtually all of which is captured by control devices.8 In 6 EPA, Mercury Study Report to Congress, Vol. 1, EPA-452/R-97-003 (Dec. 1997), EPA-HQ-OAR-2009-0234-3054 (“Mercury Study”), JA___-___. 7 EPA, Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units, Final Report to Congress, Vol. 1, EPA-453/R-98-004a (Feb. 1998), EPA-HQ-OAR-2009-0234-3052 (“Utility Study”), JA___-___. 9 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 34 of 105 the Utility Study, EPA found that only two coal-fired facilities had cumulative carcinogenic risks from HAP metals greater than one in one million, and neither exceeded three in one million. Utility Study at 6-3 to 6-4, JA___-___. Exposure levels for non-carcinogenic effects were far below the reference concentration. Id. And emission of the non-carcinogenic “acid gases” like hydrogen chloride, meanwhile, result in exposures an order of magnitude or more below healthprotective thresholds, according to EPA’s own models. Id. at 6-7, JA___. Given the uncertainties, however, EPA stated it “believes that mercury from coal-fired utilities is the HAP of greatest potential concern” and that “[f]urther research and evaluation are needed to gain a better understanding of the risks and impacts of utility mercury emissions.” Id. at ES-27, JA___. For other HAPs, EPA noted “potential concerns and uncertainties that may need further study.” Id. The December 2000 “Notice of Finding” − In December 2000, well before EPA could complete the data collection and research on mercury it said was necessary, then-departing Administrator Browner published a “[n]otice of regulatory finding,” announcing her conclusion that regulation of two EGU HAPs—mercury from coal-fired EGUs and nickel from oil-fired EGUs—was “appropriate and 8 EGUs generally use electrostatic precipitators or fabric filters to capture 99 percent or more of particulate matter emissions to comply with other CAA requirements. See, e.g., EPA, Air Pollution Control Technology Fact Sheet; Dry Electrostatic Precipitator (ESP) – Wire-Plate Type at 1, Tbl. 1, EPA-452/F-03-028 (undated), JA___. 10 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 35 of 105 necessary” under § 112. 65 Fed. Reg. 79,825, 78,829 (Dec. 20, 2000) (“2000 Finding”), JA___. EPA claimed “it is unnecessary to solicit … public comment on today’s finding [because] … [t]he regulation developed subsequent to the finding will be subject to public review and comment.” Id. at 79,831, JA___. In that future rulemaking, she explained, EPA would invite comment on the “notice of regulatory finding,” develop refined risk estimates, and consider alternative control strategies. Id. at 79,830, JA___. The 2005 “Not Appropriate” Rulemaking Determination − In 2004, EPA initiated rulemaking to address emissions from coal- and oil-fired EGUs under § 112(n)(1)(A). 69 Fed. Reg. 4652 (Jan. 30, 2004), JA___. The Agency solicited comments on its 2000 “notice of regulatory finding” and a number of regulatory options including: (1) no further regulation of EGU mercury emissions; (2) adoption of a § 112(d) rule regulating only EGU mercury emissions; (3) adoption of rules under § 112(n)(1)(A) addressing any EGU emissions that warrant regulation as “appropriate and necessary”; and (4) adoption of rules under other CAA sections to confirm that further control under § 112 is not appropriate and necessary. Id. at 4659-62, JA______. In support of this rulemaking, EPA’s modeling showed that only a small fraction of the mercury deposited in the U.S. comes from domestic EGUs, and that EGUs contribute a “relatively small percentage” to fish tissue methylmercury levels after implementation of other CAA requirements. 70 Fed. Reg. at 16,019-20, JA___11 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 36 of 105 ___. “Because this new information demonstrates that the level of [mercury] emissions projected to remain ‘after imposition of’ section 110(a)(2)(D) does not cause hazards to public health,” consistent with earlier findings, supra pp. 4, 9-10, EPA “conclude[d] that it is not appropriate to regulate coal-fired Utility Units under section 112 on the basis of [mercury] emissions,” 70 Fed. Reg. at 16,004, JA___. As it had under the 1970 and 1977 versions of the Act, EPA found that EGU emissions of non-mercury HAPs were too insignificant to warrant regulation. Id. at 16,006, JA___. Indeed, EPA found the excessive costs of § 112 regulation showed such regulation was not appropriate because “the lower bound cost of regulating under CAA § 112 beyond CAIR [a § 110 regulation for EGUs] (e.g., $750 million) exceeds the upper bound estimate of the benefits of such regulation (e.g., $210 million).” 71 Fed. Reg. 33,388, 33,394 (June 9, 2006), JA___. EPA instead regulated mercury emissions from EGUs under § 111 to ensure use of advanced emission controls regardless of public health risk, 70 Fed. Reg. 28,606 (May 18, 2005) (Clean Air Mercury Rule), JA___, reversed the 2000 Finding, and removed EGUs from the § 112(c) list of source categories, 70 Fed. Reg. at 15,994, JA___. New Jersey v. EPA − In litigation over EPA’s 2005 finding and delisting of EGUs, no party challenged the determination that it is “not ‘appropriate’ to regulate power plants under section 112 because to do so would not be cost-effective.” See Final Br. of Resp’t EPA at 84, New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008) (No. 05-1097); see also id. at 10 (EPA’s counsel informing this Court that the costs of 12 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 37 of 105 regulating EGUs under the § 112 program are “extreme” while the health benefits are “nominal”). Nonetheless, this Court vacated both EPA’s decision to remove EGUs from the § 112(c) source category list and its rule regulating mercury emissions under § 111. New Jersey, 517 F.3d 574. The Court held that, once included on the § 112(c) list by way of the December 2000 “notice of finding,” the only way for EPA to remove EGUs from that list was by making the “de-listing” showings required by § 112(c)(9) for all other source categories. Id. at 581-82. Because EPA did not follow the § 112(c)(9) procedure, the Court vacated the § 112 finding and the § 111 Clean Air Mercury Rule. Id. at 583. The Court did not rule on EPA’s 2005 determination that regulation of EGU emissions under § 112 was not “appropriate and necessary.” The MATS Rule − On remand from New Jersey, EPA proposed the Mercury and Air Toxics Standards (“MATS”) rule in May 2011, 76 Fed. Reg. 24,976 (May 3, 2011), JA___, and finalized it in February 2012, 77 Fed. Reg. 9304 (Feb. 16, 2012), JA___. In that rulemaking, EPA asserted, based on newer information, that EGU HAP emissions presented several public health and environmental risks. But those risks, in fact, were relatively small and had not changed much from EPA’s previous assessments. For mercury, the only HAP for which EPA could quantify any benefits of regulation, the Agency found, as it had before, “potential health risks do not likely result from [mercury] inhalation exposures associated with [mercury] emissions from utilities.” 76 Fed. Reg. at 25,000, JA___; see also Utility Study at 6-3, Tbl. 6-1, 7-44, 713 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 38 of 105 45, JA___, ___, ___. But the greatest health concern associated with mercury, EPA asserted, was consumption of methylmercury, 76 Fed. Reg. at 24,999, JA___, of which only an exceedingly small portion results from EGU emissions.9 EPA identified $4 to $6 million in benefits to reduce these emissions due to a very small calculated IQ loss for some hypothetically exposed persons, 77 Fed. Reg. at 9428, JA___, and asserted that there could be other unquantifiable benefits, id. at 9306, 9323, 9426-32, JA___, ___, ___-___. For trace non-mercury metals, EPA found only four coal-fired EGUs in the entire industry presenting a cancer risk greater than the de minimis risk threshold of one in one million, with the highest just five in one million. Id. at 9319, JA___. While the results of these higher risks were associated with contaminated sampling data, see UARG Comments at 11-12, JA___-___,10 even if correct, a risk of five in one million from just a few units is well within the range that EPA has previously determined is 9 EPA, Revised Technical Support Document: National-Scale Assessment of Mercury Risk to Populations with High Consumption of Self-caught Freshwater Fish In Support of the Appropriate and Necessary Finding for Coal- and Oil-Fired Electric Generating Units at 65, EPA-452/R-11-009 (Dec. 2011), EPA-HQ-OAR-2009-023419913 (“U.S. [mercury] deposition is generally dominated by sources other than U.S. EGUs”), JA___; id. at 64, Tbl. 2-2 (median “percent of total mercury deposition attributable to U.S. EGUs” in a given watershed is about 1%), JA___. 10 The issue of EPA’s arbitrary and capricious reliance on contaminated sampling data in its “appropriate and necessary” finding is the subject of an appeal by Petitioner UARG in a related case, ARIPPA v. EPA, No. 15-1180 (D.C. Cir. filed June 22, 2015), which will be submitted and argued before the same panel as the instant case. Order at 2, ARIPPA v. EPA, No. 15-1180, and Murray Energy Corp. v. EPA, No. 16-1127 (D.C. Cir. Aug. 29, 2016), ECF No. 1632520. 14 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 39 of 105 sufficient to protect public health and the environment with an “ample margin of safety.” See NRDC v. EPA, 529 F.3d 1077, 1081-83 (D.C. Cir. 2008). Accordingly, EPA did not quantify any benefits from regulating trace non-mercury metals. For acid gases, EPA’s modeling showed, as it had before, that human exposures to EGU acid gas emissions are an order of magnitude or more below conservative health-protective levels. 76 Fed. Reg. at 25,016, JA___; see Utility Study at 6-7, JA___. Therefore, the only potential environmental risk EPA could identify was that in areas where acidification already exists, hydrogen chloride emissions “could exacerbate these impacts.” 76 Fed. Reg. at 25,050 (emphasis added), JA___.11 Because risks associated with EGU emissions remained so small, EPA interpreted § 112(n)(1)(A) to require regulation of all HAPs emitted by EGUs under § 112 if any HAP emitted by any EGU was projected to create either an environmental risk or a public health risk greater than a “one-in-one million” risk level. See 77 Fed. Reg. at 9310-11, 9325-26, 9358, JA___-___, ___-___, ___. Because it found such risks for non-mercury metals and acid gases, and because mercury is a neurotoxin, EPA reversed its 2005 rulemaking determination that regulation of EGU HAP 11 Arguing it had no obligation to do so, EPA did not quantify “the precise contribution of power-plant acid gas emissions to ecosystem acidification,” Br. for the Fed. Resp’ts in Opp’n at 31, Michigan v. EPA, 135 S. Ct. 2699 (2015) (No. 14-46), and did not identify any EGU contributing to such “exacerbation,” see 77 Fed. Reg. at 9404 (noting “information gaps regarding facility-specific emissions”), JA___. 15 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 40 of 105 emissions under § 112 was not “appropriate and necessary.” Id. at 9355-56, 9363, JA___-___, ___. EPA found the annual cost of complying with the § 112(d) standards was $9.6 billion,12 even though the predicted health benefits were extraordinarily low (only about $4 to $6 million of quantified benefits, all from reducing mercury). See id. at 9428, JA___. The imbalance between costs and benefits is especially stark when examining the three control requirements EPA promulgated:  EPA found that the controls required to meet the standards for mercury would cost $3 billion per year, Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards at 3-10, EPA-452/R-11-011 (Dec. 2011), EPA-HQ-OAR-2009-0234-20131 (“MATS RIA”), JA___, to achieve only 20 tons of emission reductions, id. at Tbl. 3-4, JA___, and yield $4 to $6 million in quantified benefits, id. at 4-67, JA___.  EPA found that the controls required to meet the standards for nonmercury metals would cost at least $1 to $2 billion per year to achieve an unspecified amount of emission reductions and zero quantified benefits.13  EPA found that the controls required to meet the standards for acid gases (primarily scrubbers) would cost $5 billion per year, Smith Statement at 6, Tbl. 1, JA___, to achieve 39.8 thousand tons of hydrogen chloride emission 12 EPA’s $9.6 billion cost figure focuses only on compliance costs, not other costs that EPA has recognized elsewhere, like effects on work force and consumers of electricity. EPA, The Benefits and Costs of the Clean Air Act 1990 to 2010, at iii, EPA-410-R-99-001 (Nov. 1999), https://www.epa.gov/sites/production/files/201507/documents/fullrept.pdf, JA___. 13 UARG Comments, Ex. 1, The American Energy Initiative, Part 15: What EPA’s Utility MACT Rule Will Cost U.S. Consumers: Hearing Before the Subcomm. on Energy & Power of the H. Comm. on Energy & Commerce, 112th Cong. (2012) (statement of Anne E. Smith, Ph.D., at 6, Tbl. 1), EPA-HQ-OAR-2009-0234-20557 (“Smith Statement”), JA___. 16 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 41 of 105 reductions, MATS RIA at 3-10, Tbl. 3-4, JA___, an unspecified amount of other acid gas emission reductions, and yield zero quantified benefits. EPA interpreted § 112(n)(1)(A), however, to preclude consideration of these costs of regulation. 77 Fed. Reg. at 9326-27, JA___-___. EPA also claimed in its MATS RIA that the benefits of regulating EGUs under § 112 were substantially more than the costs of compliance because the SO2 emission standard it promulgated as a “surrogate” for acid gas regulation would produce reductions in PM2.5. MATS RIA at ES-3, JA___. According to EPA, the “co-benefits” of reductions in PM2.5 were the “great majority” of the quantifiable benefits to be achieved by the MATS rule. 77 Fed. Reg. at 9305, JA,___.14 At the same time, EPA emphatically maintained that these cobenefits played no role in its threshold “appropriate and necessary” finding. Id. at 9320, JA___. III. Michigan v. EPA Numerous parties petitioned for review of the MATS rule, including EPA’s finding that regulating EGU HAP emissions is “appropriate and necessary” without consideration of cost. The D.C. Circuit upheld EPA’s determination. White Stallion Energy Ctr., LLC v. EPA, 748 F.3d 1222 (D.C. Cir. 2014). The Supreme Court reversed, holding that “EPA strayed far beyond [the] bounds [of reasonable 14 In fact, the SO2 standard for regulation of acid gases constitutes both the bulk of the costs for the MATS rule (about $5 billion annually) and 95% of the alleged PM2.5-related co-benefits (about $32 to $87 billion annually). Smith Statement at 6, JA___; see also MATS RIA at 5-14, JA___. 17 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 42 of 105 interpretation] when it read § [112](n)(1) to mean that it could ignore cost when deciding whether to regulate power plants.” Michigan, 135 S. Ct. at 2707. The Court rejected EPA’s attempt to “harmonize[]” Congress’s treatment of EGUs under § 112(n)(1) with its treatment of other sources, noting that such an approach “overlooks the whole point of having a separate provision about power plants: treating power plants differently from other stationary sources.” Id. at 2710. Moreover, the Court explained that its underlying concern was not just that EPA ignored cost, but that EPA had “refused to consider whether the costs of its decision outweighed the benefits.” Id. at 2706. The Court held that “[n]o regulation is ‘appropriate’ if it does significantly more harm than good.” Id. at 2707. And while the Court did not require EPA to conduct “a formal cost-benefit analysis in which each advantage and disadvantage is assigned a monetary value,” id. at 2711, it stressed that EPA must weigh the benefits against the costs of regulating EGU HAP emissions under § 112, id. at 2707 (explaining “reasonable regulation ordinarily requires paying attention to the advantages and the disadvantages of agency decisions”). The Court emphasized that “[o]ne would not say that it is even rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few dollars in health or environmental benefits.” Id. For these reasons, the Supreme Court remanded the case for “further proceedings consistent with this opinion,” id. at 2712, and this Court remanded to the 18 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 43 of 105 Agency with the same instruction, White Stallion Energy Ctr., LLC v. EPA, No. 121100, 2015 WL 11051103 (D.C. Cir. Dec. 15, 2015). IV. The Supplemental Finding On remand, EPA proposed to address the Court’s decision in Michigan by issuing a “supplemental finding” that “consideration of cost does not alter the agency’s previous determination that it is appropriate and necessary to regulate coaland oil-fired EGUs under section 112 of the CAA.” 80 Fed. Reg. 75,025, 75,026 (Dec. 1, 2015), JA___. In doing so, EPA made clear it would “accept[] comment only on the consideration of cost in making the appropriate determination.” Id. at 75,027 (emphasis added), JA___. Neither the basis for EPA’s previous determination that “regulation under [§ 112]” was “appropriate,” nor the magnitude or significance of any public health or environmental risk associated with that determination, nor any opportunities to reduce those risks in less costly ways, were open for discussion. As EPA said, it “ha[d] already determined [in the MATS rulemaking] that HAP emissions from EGUs present significant hazards to public health and the environment,” id. at 75,038, JA___, and that prior determination would stand unless EPA found industry compliance costs excessive, id. at 75,026, JA___. EPA offered two alternative justifications for affirming, after a siloed consideration of costs, its prior finding that regulation of EGU HAPs under § 112 is “appropriate.” First, under its “preferred” alternative, EPA “interpret[s] CAA section 112(n)(1)(A) as not requiring a benefit-cost analysis.” Id. at 75,039, JA___; 81 19 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 44 of 105 Fed. Reg. at 24,429, JA___. Rather, the “focus” of EPA’s justification is whether the electric utility industry as a whole could “reasonably absorb” the costs of regulating under § 112 all of the HAPs emitted from EGUs. 80 Fed. Reg. at 75,030, JA___. In other words, if the industry were “ab[le] to afford compliance” with the MATS rule without disrupting “the generation, transmission, and distribution of affordable and reliable electricity,” regulation of all EGU HAPs would be automatically “appropriate” based on the benefits, however small, identified as the basis for the prior “appropriate and necessary” determination. Legal Memorandum Accompanying the Proposed Supplemental Finding that it is Appropriate and Necessary to Regulate Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units (EGUs) at 19-20 (undated), EPA-HQ-OAR-2009-0234-20519 (“Legal Memorandum”), JA___-___; see also 80 Fed. Reg. at 75,031, 75,038, JA___, ___; 81 Fed. Reg. at 24,424, 24,427, JA___, ___. To determine whether the costs of regulating EGUs under § 112 are “affordable,” EPA relied on the RIA performed in 2011 for the MATS rule, which predicted compliance costs of $9.6 billion per year. 80 Fed. Reg. at 75,032-33, JA______. This estimate reflects only the compliance costs with the MATS standards for the electric utility industry projected in 2011, and does not include more recent cost information or costs imposed on other sectors of the economy, nor even the full implications and attendant disadvantages and costs of regulating EGUs under § 112. EPA evaluated these projected costs using four metrics, id. at 75,033-36, JA___-___, 20 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 45 of 105 and concluded that “every one of [these metrics] supports its conclusion that costs are reasonable,” id. at 75,036, JA___. The Agency then concluded that because “the costs imposed by MATS are reasonable, it is appropriate for the EPA to regulate HAP emissions from EGUs in light of the meaningful progress the rule makes toward achieving key statutory goals and reducing the previously identified significant hazards to public health and the environment.” Id. at 75,038-39, JA___-___. Second, EPA’s “alternative” approach purported to show that regulation of EGU HAPs is “appropriate” based on a “formal benefit-cost analysis” pulled from the 2011 RIA for the MATS rule. Id. at 75,039, JA___. The Agency explained a formal benefit-cost analysis “attempts to quantify all significant consequences of an action in monetary terms in order to determine whether an action … [has] positive net benefits (i.e., benefits exceed costs).” 81 Fed. Reg. at 24,423 n.13, JA___. Under this alternative approach, EPA compared the MATS rule’s estimated $9.6 billion annual compliance costs to EPA’s estimated $37 to $90 billion in annual benefits. 80 Fed. Reg. at 75,040, JA___. Those cited benefits, however, almost exclusively consisted of the purported benefits of reductions in pollutants that are not regulated as HAPs under § 112, but are instead regulated under other CAA programs. EPA acknowledged that the monetary benefits from HAP reductions—due to health benefits from reducing mercury in fish—are worth no more than $4 to $6 million per year. Id. The remaining benefits—representing the overwhelming majority of EPA’s purported $37 to $90 billion in benefits—reflect reductions in PM2.5 ambient 21 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 46 of 105 concentrations due to lower SO2 emissions (which form PM2.5 in the atmosphere) resulting from the acid gas SO2 standard.15 When only HAP-related benefits are considered, the costs of compliance are “between 1,600 and 2,400 times as great as the quantifiable benefits from reduced emissions of hazardous air pollutants.” Michigan, 135 S. Ct. at 2706. In the final Rule, EPA adopted its supplemental finding largely as proposed, relying on both its “preferred” and “alternative” approaches to considering cost. 81 Fed. Reg. at 24,425, JA___. At the same time, EPA rejected commenters’ requests to consider less costly alternative control strategies when “evaluating the cost reasonableness of” using § 112 to regulate EGUs, insisting that “EPA is not required to consider the potential cost of alternative approaches to regulating HAP emissions from EGUs before finding that regulation is appropriate and necessary.” Id. at 24,447 (emphasis removed), JA___. These alternatives included § 111, which EPA can use to impose less costly national standards for new sources under § 111(b) and to require States to impose individually achievable control requirements for existing EGUs under § 111(d), and can do so without requiring EPA to regulate every HAP. EPA rejected considering § 111 as an alternative strategy, claiming commenters failed to “suggest a clear framework for developing standards” under § 111, 81 Fed. at 15 MATS RIA at 5-14 (explaining co-benefits), JA___; id. (“[T]he SO2 emission reductions are the main driver for the health co-benefits of this rule.”). 22 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 47 of 105 24,447, JA___, even though commenters outlined the process, EPA itself has detailed regulations for using § 111, and EPA had previously promulgated regulations for new and existing EGU emissions of mercury under § 111. Murray Comments at 33; 40 C.F.R. pt. 60, subpt. B. Another alternative strategy presented by commenters was to defer to States using their reserved authority under § 116 to regulate EGU emissions they conclude are worth reducing. Murray Comments at 32-33, JA___-___. In refusing “to evaluate the potential for state action” as an alternative control strategy, EPA interpreted § 112(n)(1) to prohibit EPA from considering such an alternative due to a purported “limitation” on its authority found in a reference in one of the studies to the “imposition of the requirements” of the CAA. EPA, Response to Comments for Supplemental Finding that it is Appropriate and Necessary to Regulate Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units at 23-24 (Apr. 2016), EPA-HQ-OAR-2009-0234-20578 (“RTC”), JA___-___; see 81 Fed. Reg. at 24,447 n.57, JA___. Finally, EPA refused to consider the full range of disadvantages resulting from regulating EGUs under § 112, limiting its evaluation to four sector-wide cost metrics, 81 Fed. Reg. at 24,424-25, JA___-___. EPA’s narrow cost analysis thus ignored the costs imposed more broadly on States, workers, communities and electricity consumers. See, e.g., RTC at 65, 90, JA___, ___. 23 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 48 of 105 SUMMARY OF ARGUMENT In determining that it was “appropriate and necessary” to regulate EGUs under § 112 of the Act in the 2012 MATS rule, “EPA refused to consider whether the costs of its decision outweighed the benefits.” Michigan, 135 S. Ct. at 2706. The Supreme Court emphatically rejected EPA’s determination, explaining “[o]ne would not say that it is even rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few dollars in health or environmental benefits.” Id. at 2707. On remand, EPA recognizes Michigan requires the Agency to weigh the costs and benefits of regulating EGU HAPs under § 112 and advances two rationales for reaffirming the appropriate and necessary determination rejected by the Supreme Court. In its “preferred approach,” EPA concludes that its previously-determined benefits of such regulation—benefits that at best are small, uncertain, and in most instances unquantifiable—are justified, so long as the utility industry, as a whole, can afford to spend $9.6 billion annually to obtain them. And other than a bald, conclusory declaration that these benefits outweigh the costs, EPA nowhere actually weighs anything, much less explains how it weighed the purported benefits against these very large costs. Nor does EPA ask whether it is “rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for” these particular benefits, 135 S. Ct. at 2707, or whether a cost of $9.6 billion annually is 24 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 49 of 105 “disproportionate to the[se particular] benefits,” id. at 2710. EPA’s “preferred approach”—its affordability analysis—ignores Michigan and violates § 112(n)(1)(A). Alternatively, EPA repackages its earlier MATS regulatory impact analysis into a “formal benefit-cost analysis” to claim large, monetized benefits from regulating EGUs under § 112. But EPA reaches this conclusion by ignoring the HAP-specific focus of § 112 and relying on purported benefits associated with incidental reductions in other, non-HAP pollutants (PM2.5, as a result of SO2 reductions). When the inquiry is properly limited to the effects of regulating EGU HAPs, EPA’s own evaluation shows that the $9.6 billion price tag unequivocally outweighs the meager $4 to $6 million in benefits that EPA calculates, even accounting for unquantified benefits. EPA cannot lawfully rely on the purported benefits of reducing non-HAP pollutants—ones regulated under numerous other CAA programs—as the basis for concluding that regulation of HAPs under § 112 is “appropriate and necessary.” In addition, considering costs in determining whether it is “appropriate” to regulate EGU HAPs under § 112 necessarily requires consideration of whether alternative, less costly control strategies are available. As the Supreme Court noted, this is reinforced by statutory context—which directs EPA to perform studies that focus on HAPs emitted by EGUs after other requirements of the Act have been implemented, to evaluate alternative control strategies for such HAPs that may warrant regulation, and to make the appropriate and necessary determination after considering these studies. Michigan, 135 S. Ct. at 2708. EPA’s refusal to consider such 25 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 50 of 105 alternative control strategies (especially regulation under § 111(d)—an alternative that Congress unlocked in the 1990 Amendments specifically for this purpose when it also enacted the current § 112) disregards the statutory framework and is inconsistent with Michigan. Finally, EPA’s supplemental finding considers only the costs of compliance of meeting the § 112(d) MATS standards. EPA’s adamant refusal to consider all costs and disadvantages, including the impacts on coal companies, communities, and workers, as well as localized impacts, is contrary to the Supreme Court’s direction for EPA on remand to “consider cost—including, most importantly, cost of compliance—before deciding whether regulation is appropriate and necessary.” Id. at 2711; see also Mingo Logan Coal Co. v. EPA, 829 F.3d 710, 737, (D.C. Cir. 2016) (Kavanaugh, J., dissenting) (Agency must consider “all of the relevant costs.”). STANDING Petitioners have standing to challenge the Rule. The Rule sets forth EPA’s finding that it is “appropriate and necessary” to regulate HAP emissions from coaland oil-fired EGUs under CAA § 112. This finding is a necessary legal prerequisite to such regulation. Several Petitioners own and operate EGUs or have members who own or operate them. By enabling EPA to regulate these units, the Rule subjects these Petitioners to emission standards that have, in some instances, required affected units to be idled; in others have required emission control technologies that are costly to install or to operate; and that have otherwise constrained EGUs’ operations. See Lujan 26 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 51 of 105 v. Defenders of Wildlife, 504 U.S. 555, 561-62 (1992) (when a party is the object of government regulation “there is ordinarily little question that the [governmental] action … has caused him injury”). The other petitioners also have standing. The Rule harms State Petitioners by raising the prices that State Petitioners themselves (not just their citizens) must pay as consumers of electricity. The Rule also subjects State Petitioners to ongoing regulatory burdens that require them to incur costs, including staff time. For example, the Michigan Department of Environmental Quality, operating under a delegation of authority from EPA, must “implement and enforce without changes the Section 112 standards promulgated by EPA,” which include the MATS rule. 63 Fed. Reg. 64,632, 64,633 (Nov. 23, 1998), JA___. Likewise, because the Rule subjects coal-fired EGUs to costly regulation, it discourages the construction of new units and causes existing units to retire or operate less often. This has the effect of harming Petitioner Murray Energy Corporation by diminishing the demand for coal in the electric generating sector. Both this Court in White Stallion and the Supreme Court in Michigan have recognized that Petitioners have standing to challenge the underlying MATS rule. STANDARD OF REVIEW The Court must set aside EPA’s action under the CAA if it is “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” CAA § 307(d)(9); 5 U.S.C. § 706. Agency action is invalid if the agency failed to consider an 27 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 52 of 105 important aspect of a problem, offered an explanation for its decision that runs counter to the evidence, or is so implausible that the decision could not be ascribed to a difference in view or the product of agency expertise. Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983). ARGUMENT I. EPA’s “Affordability” Analysis Does Not Satisfy Its Obligation To Determine Whether the Benefits of Regulating EGUs Under § 112 Are Worth the Costs. In Michigan, the Supreme Court directed EPA to weigh the benefits of regulation against the costs before determining whether it is “appropriate and necessary” to regulate HAP emissions from EGUs under § 112. 135 S. Ct. at 2707-11. In response, EPA’s “preferred approach” is to simply determine that the costs of regulation are “afford[able]” for the electric utility industry as a whole, and are therefore reasonable. Legal Memorandum at 19, JA___; see also 80 Fed. Reg. at 75,030 (“focus [of cost inquiry is] on whether the power sector can reasonably absorb the cost of compliance”), JA___. Other than a bald claim that it weighed those costs against previously-identified benefits of regulation, EPA never explained how and what standard it used for such weighing, much less why “it is even rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for” these uncertain and unquantifiable purported benefits. Michigan, 135 S. Ct. at 2707. Instead, EPA “interpret[ed] … section 112(n)(1)(A) as not requiring a benefit-cost analysis”— i.e., that EPA need not compare benefits to costs in order to determine whether the 28 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 53 of 105 benefits outweigh the costs. 80 Fed. Reg. at 75,039, JA___. EPA’s “preferred approach” ignores Michigan and violates the statute. A. EPA Must Consider Costs in Relation to Benefits To Justify its “Appropriate and Necessary” Determination. The Supreme Court held that the cost of regulation is an essential factor that EPA must consider when determining whether regulation of EGU HAP emissions under § 112 is “appropriate and necessary.” Michigan, 135 S. Ct. at 2707 (“Agencies have long treated cost as a centrally relevant factor when deciding whether to regulate.”). The Court did not simply direct EPA to consider cost in the abstract: its underlying concern was that EPA had “refused to consider whether the costs of its decision outweighed the benefits” in any way. Id. at 2706. To be sure, the Court did not require “a formal cost-benefit analysis in which each advantage and disadvantage is assigned a monetary value.” Id. at 2711. But the Court repeatedly stressed that EPA must weigh the benefits against the costs of regulating EGU HAP emissions under § 112. Id. at 2707 (explaining “reasonable regulation ordinarily requires paying attention to the advantages and the disadvantages of agency decisions”). As the Court succinctly put it, “[n]o regulation is ‘appropriate’ if it does significantly more harm than good.” Id. The Court’s emphasis on the need to compare the costs and benefits of § 112 regulation of EGU HAPs pervades its opinion in Michigan. The Court specifically faulted EPA’s refusal to “consider whether the costs of its decision outweighed the 29 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 54 of 105 benefits,” id. at 2706, stating unequivocally that “[o]ne would not say that it is even rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few dollars in health or environmental benefits,” id. at 2707. The Court indicated that the fundamental aim of considering cost in the “appropriate and necessary” analysis is to “ensure that the costs are not disproportionate to the benefits.” See id. at 2710. Even the dissent acknowledged an agency “acts unreasonably” in ignoring costs and benefits because “such a process would ‘threaten[] to impose massive costs far in excess of any benefit.’” See id. at 2716-17 (Kagan, J., dissenting) (quoting Entergy Corp. v. Riverkeeper, Inc., 556 U.S. 208, 234 (2009) (Breyer, J., concurring in part and dissenting in part)).16 This emphasis on evaluating the costs of regulating EGU HAP emissions under § 112 in relation to their benefits is not novel: comparing costs and benefits is 16 The dissent argued, however, that the § 112(d) standard-setting process itself would ensure the costs of the regulation are reasonable because the standards are set at levels that are achieved in practice, albeit by only the best performing units in the category. Michigan, 135 S. Ct. at 2719 (Kagan, J., dissenting). The majority rejected that reasoning, not just because it was not advanced by EPA, but because it does not compare benefits to costs. Using a hypothetical example, the Court observed that if “regulating power plants would yield $5 million in benefits, the prospect of mitigating cost from $11 billion to $10 billion at later stages of the program would not by itself make regulation appropriate.” Id. at 2711. That approach does nothing to “ensure cost-effectiveness,” id., or to ensure “that the costs are not disproportionate to the benefits,” id. at 2710. EPA’s “preferred approach,” which considers costs merely by finding that they are “affordable,” is similar to the dissent’s argument in that it is divorced from any measure of cost-effectiveness and is thus inconsistent with Michigan. 30 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 55 of 105 an “established administrative practice” that has long been recognized as an essential feature of rational agency decisionmaking. Id. at 2707-08. The Court has long held an agency’s interpretation of its standard-setting authority “unreasonable” where it “would give [the agency] power to impose enormous costs that might produce little, if any, discernible benefit.” Indus. Union Dep’t, AFL-CIO v. Am. Petroleum Inst., 448 U.S. 607, 645 (1980). A standard “is neither ‘reasonably necessary’ nor ‘feasible’ … if it calls for expenditures wholly disproportionate to the expected health and safety benefits.” Id. at 667 (Powell, J., concurring in part and concurring in the judgment). More recently, the Court recognized that when an agency considers costs, “whether it is ‘reasonable’ to bear a particular cost may well depend on the resulting benefits.” Entergy Corp., 556 U.S. at 225-26. Justice Breyer observed that “every real choice requires a decisionmaker to weigh advantages against disadvantages,” id. at 232 (Breyer, J., concurring in part and dissenting in part); see also id. at 232-33 (“[I]t would make no sense to require plants to spend billions to save one more fish or plankton … even if the industry might somehow afford those billions.”) (internal quotation marks and citation omitted). Congress had these very concerns in mind when it chose to “treat[] power plants differently from other sources for purposes of the hazardous-air-pollutants program.” Michigan, 135 S. Ct. at 2707. Congress and the Administration, which was heavily involved in drafting the 1990 CAA Amendments, understood that, given the reductions in HAP emissions expected to result from the Act’s new Acid Rain 31 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 56 of 105 Program, the substantial costs of also regulating EGUs under § 112 (particularly for a pollutant such as SO2 that is already extensively regulated under these other programs) “would increase power rates, while potentially providing little or no health benefit.” 136 CONG. REC. 3493 (Mar. 6, 1990) (statement of Sen. Steve Symms), JA___; see supra pp. 6-8. To avoid this result, Congress adopted § 112(n)(1)(A) so that EPA would be required to examine whether regulating EGU emissions under § 112 would be worth the costs. As Representative Oxley (co-sponsor of the 1990 CAA Amendments) explained, the purpose of § 112(n)(1)(A) was to “protect[] … the public health while avoiding the imposition of excessive and unnecessary costs on residential, industrial, and commercial consumers of electricity.” See 136 CONG. REC. 35,075 (Oct. 26, 1990) (statement of Rep. Michael Oxley), JA___. Administration officials likewise noted that the provision’s purpose was that “cost benefit and environment improvements to be achieved by application of these costs and technologies can be considered.” Energy Policy Hearing at 436, JA___. The importance of comparing costs and benefits under § 112(n)(1)(A) is also evident in the studies that Congress mandated under that section, which “‘provide a framework’” for EPA’s decision. Michigan, 135 S. Ct. at 2708. EPA was required to study “the hazards to public health reasonably anticipated to occur” from EGU HAP emissions after implementation of other CAA provisions—that is, to identify the benefits that could be gained by further regulation under § 112. CAA § 112(n)(1)(A). 32 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 57 of 105 Rather than addressing those emissions collectively, EPA’s report must describe “alternative control strategies for emissions which may warrant regulation under this section.” Id. (emphasis added). Likewise, Congress directed EPA to perform the Mercury Study to evaluate the “rate and mass” of EGU mercury emissions and “the health and environmental effects of such emissions” in addition to the cost of available control technologies, id. § 112(n)(1)(B), demonstrating that Congress was concerned with not just whether mercury emissions would remain after imposition of other CAA programs, but how much and how significant those emissions would be in relation to the costs of reducing them. Thus, the statute, congressional purpose, and “established administrative practice,” all require that EPA determine whether the benefits are worth the costs when deciding whether regulation under § 112 is “appropriate and necessary.” B. EPA’s “Preferred Approach” Ignores Michigan and the Statute. Despite the Court’s directive, EPA in its “preferred approach” carefully walled off its cost analysis from any comparison to the benefits that regulating EGU HAP emissions under § 112 might achieve. As a result, the “preferred approach” is inconsistent with Michigan and violates § 112(n)(1)(A). 1. EPA Unlawfully Failed To Weigh Costs Against Benefits. EPA asserts that “the regulation of and reduction in the significant amounts of HAP emissions from EGUs, and the presumed reduction in risk attendant to such reductions, is the benefit” that justifies EGU HAP regulation under § 112. Legal 33 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 58 of 105 Memorandum at 18 (emphasis added), JA___. As to the “risks” from EGU HAP emissions, EPA “maintain[s] [its] position from the MATS rule that the volume of HAP emissions from EGUs, including acid gas HAP emissions, may form the basis for finding that HAP emissions from EGUs pose a hazard to public health and the environment that is appropriate to regulate.” 81 Fed. Reg. at 24,450 (emphasis added), JA___. Otherwise, EPA merely points to its prior findings (findings EPA said were not open for comment, see 80 Fed. Reg. at 75,027, JA___) that at least one HAP emitted from EGUs (non-mercury metals) presents a public health risk above a one in one million risk level, that acid gases present an environmental risk, and that mercury is a known neurotoxin. 81 Fed. Reg. at 24,449, JA___; 80 Fed. Reg. 75,038, JA___. Nowhere in its preferred approach did EPA actually evaluate whether purported benefits outweigh a cost of $9.6 billion annually. Nor did EPA explain how purported benefits were weighed against such exceptionally large costs. Instead, EPA relied on an ipse dixit, declaring that it “weigh[ed] … [costs] against the many identified advantages to regulation.”17 81 Fed. Reg. at 24,421, JA___. All but ignoring Michigan, EPA did not even ask whether it was “rational, never mind ‘appropriate,’ to impose 17 EPA’s ipse dixit is reminiscent of a Churchill Martini. Reportedly, Sir Winston Churchill, when asked how much vermouth he wanted in his martini, replied, “‘I would like to observe the vermouth from across the room while I drink my martini.’” Warren Dockter, How to drink like Winston Churchill, THE TELEGRAPH (Jan. 28, 2015), http://www.telegraph.co.uk/news/winston-churchill/11374144/How-to-drink-likeWinston-Churchill.html. Similarly, EPA here “weighs costs” by observing them from across the room. 34 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 59 of 105 billions of dollars in economic costs in return for” these particular benefits, 135 S. Ct. at 2707, or whether a cost of $9.6 billion annually is “disproportionate to the[se particular] benefits,” id. at 2710. Rather, as EPA described it, its focus was solely on whether the electric utility industry as a whole could “absorb” the costs of regulating all of the HAPs emitted from coal- and oil-fired EGUs under § 112. 81 Fed. Reg. at 24,424, JA___. In other words, if at least one HAP emitted by one EGU presented a one in one million public health risk of carcinogenic effects or an environmental risk, and the industry was “ab[le] to afford compliance” with the MATS rule without disrupting “the generation, transmission, and distribution of affordable and reliable electricity,” then regulation of all EGUs for all HAPs they emit would be “appropriate” regardless of the magnitude of the benefit. See Legal Memorandum at 19-20, JA___-___; 80 Fed. Reg. at 75,030, JA___; see also id. at 75,031, 75,038, JA___, ___; 81 Fed. Reg. at 24,424, 24,427, JA___, ___. But finding that regulating EGUs under § 112 is “affordable” is a far cry from demonstrating its advantages are worth the burdens imposed, as § 112(n)(1)(A) and Michigan require. See AFL-CIO, 448 U.S. at 668 n.4 (Powell, J., concurring in part and concurring in the judgment) (“The cost of complying with a standard may be ‘bearable’ and still not reasonably related to the benefits expected.”). Stated another way, under EPA’s “affordability” analysis, the fact that over 99 percent of EGUs present risks of carcinogenic effects from non-mercury metal 35 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 60 of 105 emissions of less than one in one million—and that all present risks of less than five in one million, 77 Fed. Reg. at 9319, JA___—is irrelevant. That EGU acid gas emissions present no public health risk and constitute less than one percent of U.S. emissions with acidification potential,18 is irrelevant. That EPA can quantify only $4 to $6 million in public health benefits associated with reducing EGU mercury emissions is irrelevant. Indeed, according to EPA, Congress determined that HAPs are “inherently harmful,” and the only way to avoid regulating EGUs under § 112 for HAP emissions that present no public health risk is not through a § 112(n)(1)(A) determination that “such regulation” is not appropriate, but rather “to petition the Administrator to remove those pollutants from the CAA section 112(b) list” for all sources, including non-EGU sources for which no cost-benefit analysis is allowed or required under § 112. See 81 Fed. Reg. at 24,450, JA___. This is not the cost-benefit analysis called for by Michigan or the statute. See supra Section I.A. EPA’s rationale continues to ignore the fact that Congress treated EGUs differently from every other source of HAPs. See Michigan, 135 S. Ct. at 2707. If the main consideration for whether to regulate EGUs under § 112 was that EGUs emit a certain volume of HAPs—a basic fact that Congress and the other parties involved in drafting the 1990 CAA Amendments understood—then it would have made no sense 18 Comments of Electric Power Research Institute on EPA’s Proposed MATS Rule at 3-46 to 3-48 (Aug. 4, 2011), EPA-HQ-OAR-2009-0234-17621, JA___-___. 36 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 61 of 105 to enact § 112(n)(1) at all. See id. at 2710 (“[I]f uncertainty about the need for regulation were the only reason to treat power plants differently, Congress would have required the Agency to decide only whether regulation remains ‘necessary,’ not whether regulation is ‘appropriate and necessary.’”). By relying simply on its finding that the costs are “affordable” and failing to weigh these costs against the benefits of its decision, EPA’s new determination continues to violate the statute and Michigan. 2. EPA Errs By Interpreting § 112(n)(1)(A) Not To Require Any Comparison of Costs and Benefits. EPA attempts to justify its refusal to compare the costs and benefits of regulation under § 112 on the grounds that neither the statute nor Michigan require “benefit-cost analysis … to support a finding that regulation is appropriate.” Legal Memorandum at 26, JA___; see also 80 Fed. Reg. at 75,031 (“[A] benefit-cost analysis is not required to support a threshold finding that regulation is appropriate.”), JA___; id. at 75,039 (EPA “interprets CAA section 112(n)(1)(A) as not requiring a benefitcost analysis.”), JA___; 81 Fed. Reg. at 24,429 (“EPA disagrees that a benefit-cost analysis, particularly one that only … monetized HAP … benefits, … is required by CAA section 112(n).”), JA___. In fact, EPA asserts the statute requires no “finding of an economic positive net benefit” associated with regulation “under this section” at all. 81 Fed. Reg. at 24,429, JA___. EPA says this position is consistent with what EPA calls § 112’s focus on “whether the collective HAP emissions from EGUs should be 37 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 62 of 105 regulated, not the manner in which they should be regulated” under § 112. Legal Memorandum at 18, 25 (emphasis omitted and added), JA___, ___. To begin, the focus of § 112(n)(1)(A) is not on collective EGU HAP emissions, but only those posing “hazards to public health” “which warrant regulation.” EPA’s refusal to balance costs and benefits is inconsistent with § 112(n)(1)(A), as construed in Michigan, see supra Section I.A. There is no material difference between EPA’s “preferred approach” in the Rule and its 2012 “appropriate and necessary” analysis the Supreme Court rejected in Michigan. In the MATS rule, EPA found that regulation was “appropriate” because EGU HAP emissions pose some remaining but indeterminate risk to health or the environment that can be reduced through regulation. Michigan, 135 S. Ct. at 2705 (summarizing EPA’s rationale). The Supreme Court rejected this approach because, by focusing on the “need for regulation”—i.e., the existence of some remaining HAP emissions to reduce and the means to do so— EPA effectively read the term “appropriate” out of “appropriate and necessary.” See id. at 2710. On remand, EPA essentially doubles down on its rationale, adding only one caveat that cannot possibly change the result. Now, EPA says, regulation is “appropriate” because EGU HAP emissions pose some remaining but indeterminate risk to health or the environment that can be reduced through regulation that the industry, as a whole, can afford. “Affordability” to the industry, however, imposes no constraint on EPA’s authority at all—especially with respect to this industry, in which 38 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 63 of 105 customers are heavily dependent on the service provided and there is a wellestablished process for regulated sources to recover costs of compliance. As the Supreme Court recognized in AFL-CIO, a program of “pervasive regulation limited only by the constraint of feasibility” would reflect “unprecedented power over American industry” and “would give [the agency] power to impose enormous costs that might produce little, if any, discernible benefit.” 448 U.S. at 645. Yet that is precisely how EPA envisions its authority under § 112(n)(1)(A). EPA suggests in the Rule that it may refuse to evaluate costs in relation to benefits because the benefits of reducing EGU HAP emissions are not easy to quantify. See 81 Fed. Reg. at 24,429, JA___. But even if true, this difficulty does not relieve EPA of its burden to weigh costs against benefits. Whether EPA conducts a formal cost-benefit analysis or not, reasoned decision-making, Michigan, and the CAA require EPA to explain why and how the benefits outweigh the costs. At a minimum, EPA must evaluate and explain whether the specific benefits it identified are worth the costs it estimated, or that the costs would not “do[] significantly more harm than good.” See Michigan, 135 S. Ct. at 2707. Moreover, as explained in Section II below, EPA routinely quantifies the benefits of regulation even where uncertain (as it did here when it quantified the purported IQ benefits of reducing mercury emissions). In fact, as the Michigan dissent noted, EPA is required to do so by Executive Order 12866. See id. at 2721. EPA was able to quantify the benefits associated with “the predominant exposure pathway,” 76 39 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 64 of 105 Fed. Reg. at 24,999, JA___, for EGU HAP emissions—and the record shows these benefits are far outweighed by the costs. EPA’s assertion that the collective volume of EGU HAP reductions can be a substitute for “benefit,” and its generalized reference to the “significant hazards to public health and the environment,” 81 Fed. Reg. at 24,428, JA___, is plainly an attempt to mask the minuscule benefits of regulating EGUs under § 112, especially as compared to its $9.6 billion sticker price, see supra p. 16. 3. EPA Unlawfully Fails To Assess the Costs and Benefits of Each of the Three, Multi-Billion Dollar Control Mandates. The cost-benefit imbalance is especially stark when examining each of the three control requirements EPA promulgated in MATS. See supra pp. 16-17. Any costs and benefits that exist derive solely from the pollutant-specific control requirements. Just because it may be appropriate to control one HAP under § 112 does not mean it is reasonable to control other HAPs under § 112 as well. The statute focuses on each EGU HAP “which may warrant regulation under this section.” CAA § 112(n)(1)(A). Accordingly, and especially in light of alternatives available to EPA to regulate particular HAPs and not others, see infra Section III.A, EPA must consider the cost and benefits of regulating each HAP (or group of related HAPs, such as non-mercury metals) emitted by EGUs in evaluating whether it is appropriate and necessary to regulate each. EPA flatly refused to do so. RTC at 21-22, JA___. Thus, in a situation where the benefits of regulating mercury did outweigh the 40 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 65 of 105 costs, but controlling acid gases cost $5 billion and yielded minuscule or no benefit, EPA would still illogically conclude it appropriate to regulate both (or even all) HAPs from EGUs. But in such a circumstance, “it is [not] even rational, never mind ‘appropriate’” for EPA to regulate under § 112 those HAPs that yield no benefit at all. Michigan, 135 S. Ct. at 2707. This is especially so where Congress unlocked the option of regulating only mercury under § 111 specifically to avoid such a result. See infra Section III.A. EPA’s “preferred approach” cannot be squared with § 112(n)(1)(A) and the Supreme Court’s directive in Michigan to weigh costs against benefits in determining whether regulation is “appropriate and necessary.” II. EPA’s “Alternative” Benefit-Cost Approach Is Also Invalid Because It Is Based on the “Co-Benefits” of Reducing Pollutants Other than HAPs. EPA’s “alternative” approach to considering costs fares no better. The Agency claims that a “formal benefit-cost analysis” shows that the benefits of regulating EGUs’ HAP emissions outweigh the costs. 81 Fed. Reg. at 24,421, JA___. But EPA reaches this conclusion by ignoring the HAP-specific focus of § 112 and relying on purported benefits associated with incidental reductions in other pollutants (PM2.5, resulting from SO2 reductions) that are already regulated under other provisions of the Act. Section 112(n)(1)(A) directs EPA to determine whether, after the implementation of other CAA requirements (with attendant reductions in HAP 41 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 66 of 105 emissions), the benefits of addressing the remaining risks posed by EGU HAP emissions justify the costs of regulating those HAP emissions under § 112. EPA cannot answer that question by relying on reductions in pollutants that are not the target of § 112—particularly when, as here, those reductions may not yield benefits at all. When the inquiry is properly limited to the effects of regulating HAPs, the costs unequivocally outweigh the benefits. A. Congress Did Not Authorize EPA To Regulate EGU HAP Emissions Under § 112 Based on Reductions in Pollutants Regulated Under Other CAA Programs. EPA has no authority to base its decision to regulate EGU HAP emissions under § 112 on the “co-benefits” of reducing pollutants that are not HAPs (i.e., pollutants that are not listed under § 112). Congress directed EPA in § 112(n)(1)(A) to address a specific problem: the hazards to public health caused by any HAPs emitted by EGUs after implementing other CAA programs. Congress explicitly required EPA to decide whether regulation of EGUs under § 112 is “appropriate and necessary” to address that problem, not to address health hazards caused by PM2.5 resulting from SO2 or other emissions not listed under § 112. Nothing in Congress’s singular focus on HAPs in § 112(n)(1) suggests EPA may impose costly controls on EGU HAP emissions based on reductions in other pollutants that are already extensively regulated through entirely separate programs in the Act. EPA’s alternative finding impermissibly “relied on factors which Congress has not intended it to consider.” State Farm, 463 U.S. at 43. 42 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 67 of 105 1. Section 112(n)(1)(A) Limits EPA’s Consideration to Whether the Benefits of Reducing HAPs Are Worth the Costs. Both the history and the text of § 112(n)(1)(A) demonstrate EPA has no authority to determine it is appropriate to regulate EGU HAP emissions under § 112 based on the benefits of reducing non-HAPs. As the Supreme Court noted in Michigan, Congress in 1990 “subjected power plants to various regulatory requirements” that “were expected to have the collateral effect of reducing power plants’ emissions of hazardous air pollutants.” 135 S. Ct. at 2705. These other regulatory requirements included, among others, the ongoing national ambient air quality standards (“NAAQS”) program and a new program to address acid rain under Title IV of the Act. CAA §§ 401 et seq. To comply with the latter, many plants installed “scrubbers” to reduce SO2 emissions that contribute to acid rain. 70 Fed. Reg. at 16,003, JA___. Those measures also reduced HAP emissions. Congress also enacted § 112(n)(1)(A) in 1990, requiring EPA to satisfy two conditions before it can regulate EGU HAPs. First, EPA was required to undertake the Utility Study to assess “the hazards to public health reasonably anticipated to occur as a result of emissions” of HAPs from EGUs “after imposition of the requirements” of the Act. CAA § 112(n)(1)(A). Second, EPA had to find that “such regulation is appropriate and necessary after considering the results of the study.” Id. (emphasis added). Thus, the operative statutory provision explicitly limits EPA’s 43 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 68 of 105 authority to regulate any remaining EGU HAPs to the extent that the effects of those HAP emissions justify regulation. Nothing elsewhere in § 112(n)(1) gives EPA authority to base its “appropriate” finding on the benefits of regulating non-HAPs. For example, the next subsection— § 112(n)(1)(B)—requires EPA to conduct a second study (the Mercury Study) on the costs of technologies that can control “mercury emissions from electric utility steam generating units.” And the following subsection requires EPA to conduct a third study on “the threshold level of mercury exposure below which adverse human health effects are not expected to occur.” Id. § 112(n)(1)(C). These additional studies confirm that Congress in § 112(n)(1) focused on the hazards to public health caused by EGU HAP emissions (including mercury), and required that EPA base its decision on the health risks from those pollutants, not the risks from non-HAPs. See Michigan, 135 S. Ct. at 2708 (studies required by § 112(n)(1)(B) and (C) inform scope of “appropriate and necessary” analysis). EPA’s claim, 81 Fed. Reg. at 24,438-39, JA___-___, that § 112(n)(1) implicitly allows the Agency to rely on PM2.5 co-benefits as the basis for regulating EGU HAPs is also foreclosed by the Supreme Court’s ruling in Whitman v. American Trucking Ass’ns, Inc., 531 U.S. 457 (2001). American Trucking focused on whether EPA could consider cost when setting a NAAQS where the governing statutory provision— § 109—expressly requires the standard to be set at a level “requisite to public health” with an “adequate margin of safety.” CAA § 109(b). The Court refused to interpret 44 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 69 of 105 the statute as providing implicit authority to consider cost where authority to do so had “elsewhere, and so often, been expressly granted.” American Trucking, 531 U.S. at 467. As the Supreme Court in Michigan explained, “American Trucking thus establishes the modest principle that where the Clean Air Act expressly directs EPA to regulate on the basis of a factor that on its face does not include cost, the Act normally should not be read as implicitly allowing the Agency to consider cost anyway.” 135 S. Ct. at 2709. That principle of statutory interpretation applies with equal force here. Section 112(n)(1)(A) expressly directs EPA to make its “appropriate and necessary” finding on the basis of a factor (hazards to public health from HAPs emitted by EGUs) that on its face only addresses the benefits of reducing exposure to listed HAPs, which does not include PM2.5. Because Congress expressly addressed regulation of PM2.5 health effects in the NAAQS program, see CAA §§ 108-109, and directed that EPA make its appropriate finding in § 112(n)(1)(A) based on health hazards from EGU HAP emissions, EPA has no implicit authority to consider PM2.5 co-benefits. This Court has previously rejected EPA’s similar attempts to rely on factors other than those specified by Congress when deciding whether and how to regulate. See Am. Petroleum Inst. v. EPA, 52 F.3d 1113 (D.C. Cir. 1995) (“API”) (EPA may not base fuel requirements for reducing toxics on incidental global warming benefits); Ethyl Corp. v. EPA, 51 F.3d 1053 (D.C. Cir. 1995) (EPA may not deny fuel additive waiver on public health grounds when statute only permits denial on emission control 45 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 70 of 105 interference grounds); see also State Farm, 463 U.S. at 43 (“Normally, an agency rule would be arbitrary and capricious if the agency has relied on factors which Congress has not intended it to consider.”). In API, the Court addressed a provision that directed EPA to promulgate regulations governing reformulated gasoline with the aim of reducing emissions of volatile organic compounds and toxic air pollutants. 52 F.3d at 1115 (citing CAA § 211(k)). In response, EPA adopted a regulatory program that promoted renewable oxygenates over others—not because it achieved greater reductions in volatile organic compounds and toxics, but because it would promote “global warming benefits” and would otherwise “effect the purposes of the Act” generally. Id. at 1116-17. This Court held EPA exceeded its authority: “[t]he sole purpose of the [reformulated gasoline] program is to reduce air pollution … through specific performance standards for reducing VOCs and toxics emissions,” and not to advance other goals not specified by Congress. Id. at 1119. This was true even though the statute allowed EPA to consider the “nonair-quality and other air-quality related health and environmental impacts and energy requirements” of its reformulated gasoline regulations. CAA § 211(k). Those considerations were “subordinate” to that section’s overarching goal of reducing specific pollutants, and “the statute does not authorize [EPA] to use these factors as a basis for imposing any additional restrictions on [reformulated gasoline], even if the additional restrictions would yield some benefit among the factors to be taken into consideration.” API, 52 F.3d at 1120. 46 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 71 of 105 Here, reducing emissions of non-HAP pollutants is not even a subordinate goal of § 112. “[T]he aims and limits of the section as a whole” are focused entirely on HAP emissions. Id. Because the “sole purpose” of § 112(n)(1) is to address EGU HAP emissions, id. at 1119, EPA erred by basing its decision that regulation is “appropriate and necessary” on the potential benefits of reducing non-HAPs. 2. Predicating § 112 Regulation of EGU HAP Emissions on PM2.5 CoBenefits Resulting from SO2 Reductions Is an End-Run Around CAA Programs That Already Regulate These Non-HAPs. EPA’s lack of authority to consider PM2.5 co-benefits is further reinforced by the fact that PM2.5 is addressed under a completely different CAA provision—the § 109 NAAQS program. Under that program, EPA regulates PM2.5 and other “criteria” pollutants according to detailed legislative instructions regarding the manner and extent to which those pollutants are to be controlled. EPA cannot base a decision that it is “appropriate” to establish § 112 standards for EGU HAPs on alleged benefits of reducing another pollutant (PM2.5) beyond the levels EPA has already determined meet the statutory directives applicable to that pollutant. Indeed, at oral argument in Michigan, Chief Justice Roberts described relying on co-benefits as “an end run” around § 109’s restrictions. Tr. of Oral Arg. at 59-61, Michigan v. EPA, 135 S. Ct. 2699 (2015) (No. 14-46); see also id. at 62-63 (noting EPA’s citation of co-benefits “raises the red flag”). EPA’s reliance on PM2.5 co-benefits is particularly egregious here, because these co-benefits largely result from reductions in SO2 obtained through the installation and 47 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 72 of 105 upgrade of scrubbers forced by the § 112(d) standard for acid gases. In the 1990 Amendments, Congress decided to treat EGUs differently from all other source categories under § 112 in no small part because of concerns that § 112(d) standards would undo the efficiency of the Title IV program by mandating uniform controls of acid gases so as to eliminate the flexibility, freedom of choice, and efficiency that are the core goals of Title IV. See, e.g., Murray Comments at 16 (statement of Sen. Gerry Sikorski) (“[F]reedom of choice would be wasted” if § 112 is used to “require most, if not all coal-fired units to scrub.”), JA___; 136 CONG. REC. 35,013 (Oct. 26, 1990) (statement of Rep. Howard Nielson) (“It is the sense of the conferees that EPA’s ultimate decision avoid any conflict with title IV implementation, including the compliance flexibility and cost-effectiveness goals which are central to the acid rain program.”), JA___; Murray Comments at 18-19 (quoting statements of Sens. Malcolm Wallop and Wendell Ford), JA___-___. Title IV’s Acid Rain Program was exhaustively negotiated by Congress to reduce EGU SO2 emissions using “prescribed emission limitations,” “specified deadlines,” and an “emission allocation and transfer system.” CAA § 401(b). The trading program was included to provide for the strategic and non-universal deployment of scrubbers while allowing those with the highest retrofit costs to avoid installing them in exchange for subsidizing emission reductions achieved at other EGUs. Thus, Congress itself determined the best approach to cost-effectively reduce EGU SO2 emissions. EPA’s attempt to justify using § 112 based on additional 48 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 73 of 105 reductions of this very same pollutant from these very same sources, but in a command-and-control program that is the antithesis of Title IV’s market-based program, is plainly an “end run” around the latter. B. EPA’s Arguments for Relying on Co-Benefits Are Unavailing. 1. EPA’s Invocation of General “Economic Principles” Is Irrelevant. EPA maintains that its “formal” benefit-cost analysis may include incidental cobenefits because doing so is consistent with “standard economic principles.” 81 Fed. Reg. at 24,439, JA___. “Standard economic principles,” however, cannot override the requirements of § 112(n)(1)(A). Indeed, no economic principle endorses the consideration of costs or benefits that are irrelevant for a given context. And the context here, as discussed above, is Congress’s command in § 112(n)(1)(A) for EPA to determine whether the risks from EGU HAP emissions justify the costs of regulating those emissions under § 112. Whatever role co-benefits may play in other economic analyses, they have no place in EPA’s “appropriate and necessary” analysis. Indeed, EPA’s own policy for conducting benefit-cost analyses demonstrates this very point. See EPA, Guidelines for Preparing Economic Analyses (Dec. 17, 2010, updated May 2014), https://www.epa.gov/environmental-economics/guidelinespreparing-economic-analyses. The Guidelines do not advise that EPA consider all conceivable effects of a regulation: they state that EPA must identify the “relevant economic variables” based on the “environmental problem that the regulation addresses.” Id. at 5-3 (emphasis added), JA___. The “environmental problem” that 49 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 74 of 105 Congress instructed EPA to address in § 112(n)(1)(A) is the hazard to public health from EGU HAP emissions after implementation of other CAA programs, not the risks posed by emissions of other pollutants already regulated under other provisions of the Act. Under EPA’s own guidelines, PM2.5 co-benefits are not a “relevant economic variable” and cannot be used as the basis for a determination to regulate EGU HAPs. 2. EPA’s Justification for Considering Co-Benefits Relies on a Logical Fallacy. Congress understood that programs targeted at reducing pollutants other than HAPs (like SO2 in Title IV’s Acid Rain Program) may result in collateral reductions of HAPs. Congress therefore required EPA to perform the Utility Study to determine “the hazards to public health reasonably anticipated to occur as a result of emissions by” EGUs of HAPs “after imposition of” these programs. CAA § 112(n)(1)(A). EPA asserts that because it must determine in the Utility Study the extent to which CAA programs addressing non-HAP pollutants will reduce risks from EGU HAP emissions, it may conversely consider risks from non-HAP pollutants when determining whether regulation of EGU HAP emissions is “appropriate and necessary.” 81 Fed. Reg. at 24,438-39, JA___-___. The Agency’s argument is a red herring. Had Congress intended that EPA regulate under § 112 based on health effects of HAP and non-HAP EGU emissions, it would have said so. It did not. Congress in the Utility Study asked EPA to address two questions: (1) what EGU HAP emissions 50 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 75 of 105 remain after controls under other programs; and (2) what HAP risks are posed by those remaining HAP emissions. Congress’s exclusive focus in § 112(n)(1)(A) is on EGU HAP emissions. The sole purpose of the Utility Study and the “appropriate and necessary” requirement in § 112(n)(1)(A) is thus to determine whether EGUs’ remaining HAP emissions pose significant risks and should be regulated under § 112. Ancillary PM2.5 “co-benefits” play no role in answering that question. 3. EPA Relies on the Illusory Co-Benefits of Reducing PM2.5 Below Levels That the Agency Has Already Found Protect the Public Health. Even if EPA had the legal authority to consider PM2.5 co-benefits for its “appropriate and necessary” finding, the PM2.5 co-benefits on which it relies are illusory. The Agency determined in 2013 when it analyzed the PM2.5 NAAQS that its confidence in the association between reducing PM2.5 below the level already required by the NAAQS (12 µg/m3) and the health benefits from such additional reductions is inadequate to conclude that any additional reductions are warranted. 78 Fed. Reg. 3086, 3116 (Jan. 15, 2013), JA___; see also id. at 3089 (stating that 12 µg/m3 provides the “appropriate degree of increased public health protection”) (emphasis added), JA___. Yet most of the PM2.5 reductions EPA cites to support its “appropriate and necessary” finding occur in areas that have already attained the NAAQS. MATS RIA at ES-4, JA___. EPA cannot justify its decision to regulate EGU HAPs under § 112 based on asserted public health benefits it only recently concluded did not justify regulation of those non-HAPs. 51 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 76 of 105 Section 109 requires EPA to promulgate “primary” NAAQS for criteria pollutants, like PM2.5. CAA § 109(b). Primary NAAQS are defined as standards “which in the judgment of the Administrator, based on such criteria and allowing an adequate margin of safety, are requisite to protect the public health.” Id. § 109(b)(1).19 When setting a primary NAAQS with an “adequate margin of safety,” the Administrator must decide “what margin of safety will protect the public health from the pollutant's adverse effects—not just known adverse effects, but those of scientific uncertainty or that ‘research has not yet uncovered.’” Am. Lung Ass’n v. EPA, 134 F.3d 388, 389 (D.C. Cir. 1998) (quoting Lead Indus. Ass’n, Inc. v. EPA, 647 F.2d 1130, 1153 (D.C. Cir. 1980)). The NAAQS must protect “not only average healthy individuals, but also ‘sensitive citizens.’” Id. at 389; see American Trucking, 531 U.S. at 475-76. In 2013, EPA reviewed the most recent scientific research and revised the NAAQS for PM2.5. 78 Fed. Reg. 3086, JA___. The Administrator explained that when selecting the ambient concentration that would protect public health with an adequate margin of safety, her judgment was informed by “the degree of confidence in the observed associations in the epidemiological studies” between exposure to PM2.5 and 19 The Act also requires EPA to promulgate “secondary” standards to protect the public welfare, including crops and buildings, from the effects of air pollution. CAA §§ 109(b)(2), 302(h). The secondary NAAQS for PM2.5 are all less stringent than or equal to the corresponding primary NAAQS. See 40 C.F.R. §§ 50.13, 50.18. 52 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 77 of 105 adverse health effects. Id. at 3161, JA___. As to the level of the standard, EPA found, “the available evidence interpreted in light of the remaining uncertainties does not justify a standard level set below 12 µg/m3 as necessary to protect public health with an adequate margin of safety.” Id. at 3162, JA___. Put another way, although NAAQS are “precautionary and preventive” in nature, Lead Indus. Ass’n, Inc., 647 F.2d at 1155, and intended to protect the most sensitive subgroups in the population, EPA did not have confidence that a level below 12 µg/m3 was needed to provide the rigorous protections the Act requires. Indeed, EPA explained any health benefits that may occur at PM2.5 concentrations below 12 µg/m3 are not merely “less certain”—they are so uncertain that it is not appropriate to include exposures below 12 µg/m3 within the “adequate margin of safety” provided by the NAAQS. See 78 Fed. Reg. at 3161, JA___. EPA’s lack of confidence in any such benefits was so low that a standard below 12 µg/m3 “would not be warranted.” Id. Yet EPA now claims that reductions of PM2.5 (as a result of a § 112(d) standard that forces installation of scrubbers to reduce SO2) below the current PM2.5 NAAQS level will provide additional health benefits worth $37 to $89 billion each year. EPA has not identified any new scientific information that would overcome its 2013 determination that an ambient PM2.5 concentration of 12 µg/m3 is not only sufficient to protect the public health—including sensitive citizens—but will do so with an adequate margin of safety. Nor has it explained why it now has sufficient confidence 53 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 78 of 105 in the existence of health benefits from further reductions in PM2.5 when in 2013 it did not. In fact, EPA asserts that almost all of the “estimated avoided premature deaths” on which the purported co-benefits are based would occur in areas where the concentration of PM2.5 in the ambient air is below 10 µg/m3—lower than even the current 12 µg/m3 PM2.5 NAAQS. MATS RIA at ES-4, JA___. Nevertheless, EPA, without explanation, “considers them to be legitimate components of the total benefits estimate.” Id. In sum, EPA’s recent findings establish that reductions in PM2.5 concentrations beyond those already required by the revised NAAQS do not provide any reliable benefits at all, much less benefits that could amount to $37 to $89 billion every year. Equally important for this case, EPA has not explained its reliance on the “benefits” of reducing PM2.5 concentrations below the NAAQS in light of its 2013 conclusion that it has no confidence in the existence of those benefits. See FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515-16 (2009) (Where action “rests upon factual findings that contradict those which underlay its prior policy …. a reasoned explanation is needed for disregarding facts and circumstances that underlay or were engendered by the prior policy.”). Because EPA has not provided an “explanation for its action” that includes “a ‘rational connection between the facts found and the choice made,’” the appropriate finding is arbitrary and capricious. State Farm, 463 U.S. at 43 (quoting Burlington Truck Lines v. United States, 371 U.S. 156, 168 (1962)). 54 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 79 of 105 Finally, even if EPA now has greater confidence that health benefits would accrue from further reductions in PM2.5 levels, the Act’s NAAQS provisions—and not § 112(n)(1)—provide a mechanism for implementing such reductions. Each NAAQS and the related scientific evidence supporting it must be reviewed at least every five years, resulting in NAAQS revision if appropriate. CAA § 109(d)(1). In fact, EPA has already begun to review the 12 µg/m3 PM2.5 NAAQS. See 81 Fed. Reg. 22,977 (Apr. 19, 2016), JA___. Any health benefits potentially available from further reducing PM2.5 levels are properly addressed and accounted for through the NAAQS program, not through regulating EGU HAP emissions under § 112. C. EPA’s Vague Reference to Unquantifiable Benefits Does Not Support Its “Appropriate and Necessary” Finding. The cited PM2.5 co-benefits of $36 to $89 billion per year are the primary justification for EPA’s conclusion in its alternative approach that the benefits of regulating EGU HAP emissions under § 112 outweigh its costs. See MATS RIA at ES3, JA___. When these co-benefits are eliminated from EPA’s analysis, the quantified net benefits are overwhelmingly negative: as the Supreme Court noted, the costs of the MATS rule are “between 1,600 and 2,400 times as great as the quantifiable benefits from reduced emissions of [HAPs].” Michigan, 135 S. Ct. at 2706. In light of this imbalance, regulating EGU HAP emissions under § 112 clearly “does significantly more harm than good” and is not “appropriate.” Id. at 2707. The vague un-monetized HAP-related benefits EPA alludes to cannot alter this conclusion. See 80 Fed. Reg. at 55 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 80 of 105 75,040 (claiming EPA “accounted for” unquantified benefits “by adding a ‘+B’ to denote the sum of all unquantified benefits”), JA___. Aside from the meager $4 to $6 million in benefits EPA quantified for “the predominant exposure pathway by which humans are affected by [methylmercury],” 76 Fed. Reg. at 24,999, JA___, the Agency otherwise points to empty generalities and speculative claims regarding health and environmental effects. For example, EPA asserts that the benefits of regulation include “the statutory goal of reducing the inherent hazards associated with HAP emissions.” 81 Fed. Reg. at 24,429, JA___. But the Supreme Court has already rejected this rationale, noting that the fact some reduction in HAPs will occur is not sufficient to make such regulation “appropriate.” See Michigan, 135 S. Ct. at 2710 (“[I]f uncertainty about the need for regulation were the only reason to treat power plants differently, Congress would have required the Agency to decide only whether regulation remains ‘necessary,’ not whether regulation is ‘appropriate and necessary.’”). EPA also claims that, even though it was able to quantify highly uncertain IQ benefits purportedly resulting from mercury emissions, other health and environmental benefits of reducing EGU mercury, acid gas, and non-mercury metals emissions simply could not be quantified. 81 Fed. Reg. at 24,441, JA___; 80 Fed. Reg. at 75,040, JA___. But these purported benefits are too speculative to support an “appropriate and necessary” finding for the same reasons the Agency cannot quantify them: they are not supported by the scientific literature. See 80 Fed. Reg. at 75,040, 56 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 81 of 105 JA___. As the Agency acknowledges, at the low exposures presented by EGU HAP emissions, benefits cannot be quantified due to gaps in toxicological data, uncertainties in extrapolating results from high-dose animal experiments to estimate human effects at lower doses, limited monitoring data, difficulties in tracking diseases such as cancer that have long latency periods, and insufficient economic research to support the valuation of the health impacts often associated with exposure to individual HAP. Id. at 75,040 n.53, JA___; see also, e.g., MATS RIA at 64-66, JA___-___. Finally, even if the science allowed one to establish additional benefits of reducing EGU HAP emissions with any confidence, EPA makes no effort to demonstrate that these benefits would be significant enough—in combination with the $4 to $6 million in quantifiable benefits—to justify the $9.6 billion in compliance costs required by the MATS rule. Even if the unquantified benefits EPA cites are worth ten times the benefits for the “predominant exposure pathway” it can quantify, they would still be orders of magnitude less than the costs of this regulation. The Court stated that “[i]f (to take a hypothetical example) regulating power plants would yield $5 million in benefits, the prospect of mitigating cost from $11 billion to $10 billion ... would not by itself make regulation appropriate.” Michigan, 135 S. Ct. at 2711. Likewise, if regulating EGU HAP emissions would cost nearly $10 billion, increasing the benefits from $5 million to $6 million (or even $50 million) would not make regulation appropriate. 57 USCA Case #16-1127 III. Document #1647029 Filed: 11/18/2016 Page 82 of 105 EPA’s Refusal To Consider Alternative Control Strategies and All Relevant Costs, Is Contrary to the Statute and the Supreme Court’s Direction. A. EPA Impermissibly Ignores Less Costly Alternative Control Strategies for Reducing Emissions from EGUs. In the final Rule, EPA limited its analysis to the costs of MATS (and only to some of those costs, see Section III.B infra), and refused to consider alternative control strategies that would avoid many of the disadvantages resulting from costly regulation of EGUs under § 112, which requires emission standards based on uniform national standards set at the levels achieved by the best performing EGUs. CAA § 112(d)(3), (d)(3)(A). EPA’s refusal to consider such alternatives as part of its “appropriate and necessary” determination is contrary to Michigan and violates the statute. Congress directed EPA to perform the Utility Study and, in reporting on that study, to “develop and describe” “alternative control strategies for emissions which may warrant regulation under this section.” Id. § 112(n)(1)(A). EPA may regulate EGUs under § 112 only if it finds “such regulation is appropriate and necessary after considering the results of the study required by this subparagraph.” Id. This “[s]tatutory context reinforces the relevance” of considering less costly and more flexible alternatives in assessing cost and deciding whether § 112 regulation—as opposed to regulation under another program or not at all—is “appropriate and necessary.” Michigan, 135 S. Ct. at 2708 (recognizing that “all three studies ‘provide a framework for [EPA’s] determination.’”). 58 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 83 of 105 EPA’s Rule disregards this statutory framework. EPA insists it “is not required to consider the potential cost of alternative approaches to regulating HAP emissions from EGUs before finding that regulation is appropriate and necessary” under § 112. 81 Fed. Reg. at 24,447 (emphasis omitted), JA___. EPA’s refusal even to consider how § 112 regulation compares to less costly and more flexible alternatives “overlooks the whole point” of § 112(n)(1), Michigan, 135 S. Ct. at 2710: to address the many warnings from EPA and others that regulating EGUs under § 112 could lead to massive costs with little benefits, see supra pp. 6-7 (discussing these warnings). This is why Congress directed EPA to identify alternative control strategies for reducing HAP emissions before concluding that regulation under § 112 was both “necessary” and “appropriate.” Section 112(n)(1) requires EPA to address alternatives that would “avoid any conflict with title IV implementation, including the compliance flexibility and cost-effectiveness goals which are central to the acid rain program.” 136 CONG. REC. 35,013 (Oct. 26, 1990) (statement of Rep. Howard Nielson), JA___.20 EPA did not need to look far in performing the required statutory analysis. As EPA itself has previously recognized, supra pp. 11-12 (discussing 2005 rulemaking), 20 Title IV is “flexible” and “cost-effective” because it allows some sources to install larger and more expensive scrubbers such that others can install smaller and less expensive scrubbers or avoid installing scrubbers at all, all while still achieving the desired SO2 emission reductions. See Murray Comments at 10, 13, JA___, ___. By contrast, the § 112 acid gas emission standard requires that nearly every EGU install or upgrade SO2 controls. 59 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 84 of 105 the CAA provides more effective alternative strategies for controlling EGU emissions. Indeed, Congress provided in the 1990 Amendments one such alternative precisely to “allow[] the needed flexibility to identify and address the most significant toxic chemicals from utilities without mandating expensive controls that may be unnecessary.” Administrator 1990 Letter to Senate, JA___. Specifically, § 111(d) of the Act allows EPA and States to regulate EGU emissions without imposing unreasonable burdens on existing sources, permitting States to tailor requirements for “any particular source” based on “consideration” of “remaining useful life” and “other factors.” EPA’s regulations allow States to establish “less stringent emission standards or longer compliance schedules” “on a case-by-case basis for particular” sources or “classes” of sources whenever necessary to avoid imposing any “[u]nreasonable cost of control resulting from plant age, location, or basic process design,” or to account for “[p]hysical impossibility” or any “[o]ther factors” “that make application of a less stringent standard or final compliance time significantly more reasonable.” 40 C.F.R. § 60.24(f). EPA has recognized that the 1990 Amendments to § 111(d) “reflect[] a desire to change the pre-1990 approach and to expand EPA’s authority as to the scope of pollutants that could be regulated under section 111(d)” so as not to “preclude EPA from regulating under section 111(d) those pollutants emitted from source categories which were not actually being regulated under section 112” including “existing Utility Units.” 69 Fed. Reg. at 4685, JA___. Thus, if mercury is the HAP emitted by EGUs 60 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 85 of 105 after imposition of the requirements of the Act that “may warrant regulation,” CAA § 112(n)(1)(A), then EPA can regulate that pollutant under § 111(d) without regulating other pollutants—such as acid gases—at great cost, even though those other pollutants pose no public health risk. That is what EPA did in the Clean Air Mercury Rule, promulgated under § 111(d). See supra pp. 11-12. EPA’s disregard of a less costly option that Congress unlocked specifically for the purpose of providing an alternative for regulating EGUs is especially egregious. In addition, Congress provided EPA with opportunities to defer regulation of EGU emissions to States, including using States’ preserved authority to regulate “emissions of air pollutants” under § 116. See also CAA § 102(a). To that end, § 112 requires EPA to provide States the technical information and assistance required for States to regulate HAPs, directing EPA to “establish and maintain an air toxics clearinghouse and center to provide technical information and assistance to State and local agencies … on control technology, health and ecological risk assessment, risk analysis, ambient monitoring and modeling, and emissions measurement and monitoring.” Id. § 112(l)(3). Congress also instructed EPA to “encourage and support areawide strategies developed by State or local air pollution control agencies that are intended to reduce risks from emissions by area sources within a particular urban area,” with at least ten percent of funding to support “innovative and effective” areawide strategies. Id. § 112(k)(4). By interpreting § 112(n)(1) to prohibit EPA from considering the 61 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 86 of 105 alternative of deferring to State regulation of EGU emissions as part of the appropriate and necessary determination, 81 Fed. Reg. at 24,447 n.57, JA___, EPA “strayed far beyond” the “bounds of reasonable interpretation,” Michigan, 135 S. Ct. at 2707 (internal quotation marks omitted). Besides avoiding the conflict with Title IV and the unreasonable results of imposing § 112(d) standards on EGUs, EPA’s § 111 and § 116 alternatives would give States far more say in the regulation of emissions from power plants. By interpreting § 112(n)(1) to require nationally-uniform § 112 regulation of EGU emissions if EPA found regulation was “appropriate,” EPA ignored the federalism implications of undoing a century of State and local effort and supplanting traditional State authority with the strict and inflexible § 112 program.21 EPA chose a regulatory program EPA knows will “level” the power industry by imposing national uniform emission standards. 76 Fed. Reg. at 24,979, JA___. Congress did not tie EPA’s hands in § 112(n)(1) to regulate EGUs the same as all other industries. Indeed, that was the point of § 112(n)(1), as the Supreme Court emphasized—treat EGUs differently. In addition, well-settled principles of administrative law require “consideration of alternatives” and “an adequate explanation when … alternatives are rejected.” Int’l See Murray Comments at 4-11 (detailing state and local efforts and traditional state authority over EGUs) & 47-48 (identifying and explaining the need to consider federalism concerns), JA___-___, ___-___; see generally Bond v. United States, 134 S. Ct. 2077, 2088 (2014) (statutes “must be read consistent with principles of federalism inherent in our constitutional structure”). 21 62 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 87 of 105 Ladies’ Garment Workers’ Union v. Donovan, 722 F.2d 795, 817 (D.C. Cir. 1983); see also id. (“It is absolutely clear … that … an ‘artificial narrowing of options,’ … is antithetical to reasoned decisionmaking and cannot be upheld.” (quoting Pillai v. Civil Aeronautics Bd., 485 F.2d 1018, 1027 (D.C. Cir. 1973)).22 EPA’s decision “is lawful only if it rests ‘on a consideration of the relevant factors.’” Michigan, 135 S. Ct. at 2706 (quoting State Farm, 463 U.S. at 43). Thus, EPA may not “fail to consider an important aspect of the problem when deciding whether regulation” under § 112 “is appropriate” for EGUs. Id. at 2707 (internal quotation marks and alteration omitted). EPA’s refusal to consider alternatives and explain why it rejected them is a “complete failure to satisfy these quintessential aspects of reasoned decisionmaking.” Donovan, 722 F.2d at 818. B. EPA Cannot Find § 112 “Appropriate” for EGUs Without Considering all Costs, Including Important Disadvantages and Localized Impacts. The Rule is also flawed because it provides an incomplete account of the costs of regulating HAP emissions from EGUs under § 112. The Supreme Court directed EPA to account for “more than the expense of complying with regulations.” Michigan, 135 S. Ct. at 2707. Instead, EPA must consider “any disadvantage” of using § 112. Id.; see also State Farm, 463 U.S. at 43 (EPA must “consider … important aspect[s] of the 22 See also 2 U.S.C. § 1535 (Unfunded Mandates Reform Act, requiring, inter alia, EPA to explain why the least costly method of achieving its objectives was not adopted); 5 U.S.C. § 602(c) (Regulatory Flexibility Act, requiring, inter alia, EPA to consider “significant” alternatives that minimize “significant economic impact” on small entities”). 63 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 88 of 105 problem”). EPA concedes it must “determine” that using § 112 “will, on the whole, be beneficial as opposed to detrimental to society.” 81 Fed. Reg. at 24,430, JA___. EPA cannot make that determination without considering “all of the relevant costs.” See Mingo Logan, 829 F.3d at 737 (Kavanaugh, J., dissenting). Because EPA did not examine alternative control strategies, see supra Section III.A, it ignored the relative costs of available alternative control strategies that would—and should—have informed its decision whether “regulation under this section” was “appropriate.” Indeed, if EPA is going to interpret § 112 as requiring that EGUs be regulated the same as other source categories, it must address the full implications of that decision, including the applicability of all aspects of “regulation under this section.” This includes the disadvantage of a possible second round of regulation under the § 112(f) residual risk review provision.23 See Murray Comments at 40, JA___. That possibility is a “cost” that must be considered as part of the § 112(n)(1)(A) determination, and EPA’s refusal to do so, RTC at 35, JA___, is contrary to Michigan, 135 S. Ct. at 2711.24 23 If this Court upholds the Rule, it would be unlawful for EPA to impose on EGUs in the future additional compliance costs that were not accounted for in the “appropriate and necessary” determination required by Michigan. 24 EPA refused to consider § 112(f) because it said it was not possible, at this time, to look into the future to project precisely the contours of potential § 112(f) regulation. See RTC at 35, JA___. But even if true, in Michigan, the Court rejected EPA’s similar argument that it could not consider costs of a future § 112(d) rule at the time of a § 112(n)(1)(A) determination. 135 S. Ct. at 2706-08. 64 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 89 of 105 EPA’s evaluation ignores myriad costs and disadvantages, including the localized impacts of § 112 regulation of EGUs on certain States, the coal mining industry, and consumers. Congress itself identified many disadvantages of using § 112 to regulate EGUs. See generally Murray Comments at 14-29, JA___-___. For example, Senator Ford specifically expressed concern that coal miners would be “out of work, absolutely out of work.” See id. at 19 (quoting statement of Sen. Ford, Hearing Before the Sen. Comm. on Energy & Nat. Res. (Jan. 24-25, 1990)), JA___. Members of industry raised important localized concerns before Congress in 1990, including impacts on consumers. See, e.g., id. at 15 (“[A] rate increase of this magnitude upon the rural impoverished people in our service territory would cause them undue harm.”) (quoting testimony of Gen. Counsel of Iowa Southern (June 22, 1989)), JA___; id. at 20 (“This drastic restructuring of section 112 would impose enormous cost[s] … that are especially punishing to the poor and those on fixed income ….”) (quoting testimony of Dr. Goodman, Southern Co. Vice President of Research & Envtl. Affairs, Hearing Before the Sen. Comm. on Energy & Nat. Res. (Jan. 24-25, 1990)), JA___. EPA refused to consider these disadvantages, asserting that “examining highly localized impacts ... is not required by Section 112(n)(1)(A).” RTC at 90, JA___. EPA also defended its refusal to consider impacts on coal companies, communities, and workers by citing EPA’s projection in 2012 that “coal production for the electric power sector in 2015 would decrease about 1 percent.” Id. at 92-94, JA___-___. 65 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 90 of 105 But EPA was presented with data showing that it had vastly underestimated EGU retirements. For example, the State of Ohio identified roughly 6 GW of EGU closures in Ohio alone resulting from the decision to regulate EGUs under § 112, Comments of Ohio Environmental Protection Agency at 3 & Enclosure (Jan. 15, 2016), EPA-HQ-OAR-2009-0234-20542, JA___, ___, which is more than EPA predicted for the entire country. EPA rejected this evidence in favor of blindly relying on its erroneous 2012 projections. RTC at 76 (“EPA disagrees with the commenter’s assertion that the EPA must rely on a consideration of costs that includes data on recent plant closures ….”), JA___. EPA also ignored without explanation the estimate of 19 GW of EGU closures provided by NERA Economic Consulting, id. at 78, JA___, an estimate that is consistent with the Energy Information Administration’s finding of approximately 20 GW of closures and 5.6 GW of conversions from coal to natural gas as a result of EPA’s MATS rule. U.S. Energy Information Administration, Today in Energy: EIA electricity generator data show power industry response to EPA mercury limits at 1 (July 7, 2016), http://www.eia.gov/todayinenergy/ detail.php?id=26972, JA___. Thus, actual data confirm the numerous comments showing that impacts on coal companies, communities, and workers were far greater than EPA projected, and therefore even more important to consider. Reasoned decisionmaking requires that EPA “consider … important aspect[s] of the problem” and “examine the relevant 66 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 91 of 105 data,” State Farm, 463 U.S. at 43, but EPA gave no thought at all to these especially concerning “highly localized impacts” of its decision. RTC at 90, JA___. Instead of considering all costs of regulating EGUs under § 112, EPA restricted its evaluation in the Rule to the ability of the utility sector to “absorb” compliance costs. See 81 Fed. Reg. at 24,424-25, JA___-___; supra p. 20. EPA’s sectorwide approach to assessing costs masks the real impacts of § 112 regulation. For example, EPA included States with little or no coal generation in its cost metrics, 81 Fed. Reg. at 24,435, JA___, diluting the impact of the Rule in coal-generating States. See also Murray Comments at 41-46, JA___-___. That EPA’s approach was unreasonable is further illustrated by EPA’s refusal to consider the impact of the MATS rule in the ERCOT market in Texas and on ARIPPA members. In finding the cost of the rule reasonable across the entire power sector, EPA repeatedly generalizes that “many of these sources are able to passthrough compliance costs to ratepayers.” 81 Fed. Reg. at 24,436, JA___; 80 Fed. Reg. at 75,035, JA___. Indeed, EPA’s assumption that compliance costs were recoverable was a key part of its (erroneous) conclusion that overall costs were reasonable (i.e., affordable). 81 Fed. Reg. at 24,424-25, JA___-___. But, as Luminant and other commenters pointed out, that is not true for the competitive ERCOT market, where costs are not passed on through rates and producers alone must bear the compliance costs, Comments of Luminant on EPA’s Proposed Supplemental Finding at 8-9 (Jan. 15, 2016), EPA-HQ-OAR-2009-0234-20533, JA___-___, or for Texas, ninety percent 67 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 92 of 105 of which “is covered by a single isolated grid with limited connections to external power supplies,” see Texas v. EPA, 829 F.3d 405, 431 (5th Cir. 2016). EPA’s response that it “consider[ed] all expenditures required under MATS whether these costs are borne either by electricity consumers or electricity producers,”25 is no response at all; it confirms that EPA has given costs in the ERCOT market “no thought at all,” Michigan, 135 S. Ct. at 2706. EPA’s recognition elsewhere of the economic strains on generators in the ERCOT market and Luminant units in particular, 81 Fed. Reg. at 24,433 n.24, JA___, underscores the arbitrariness of its refusal to “analyze costs to ERCOT independently” when assessing the reasonableness of the rule’s costs, RTC at 67, JA___, as well as the fact that its conclusions run counter to the evidence before the Agency (i.e., the acute economic pressures in ERCOT). State Farm, 463 U.S. at 43. The impropriety of EPA’s approach in considering only certain costs imposed by MATS is further illustrated by EPA’s failure to evaluate the cost corresponding to the lost environmental benefits resulting from the forced shutdown of bituminous coal refuse-fired sources operated by ARIPPA members. ARIPPA facilities provide a unique environmental benefit by utilizing state-of-the-art circulating fluidized bed combustion technology to convert coal refuse into energy. Comments of ARIPPA on EPA’s Proposed Supplemental Finding at 2-3 (Jan. 14, 2016), EPA-HQ-OAR-20090234-20535 (“ARIPPA Comments”), JA___-___. ARIPPA facilities combust coal 25 RTC at 67, JA___; see also 81 Fed. Reg. at 24,434, JA___. 68 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 93 of 105 refuse from both past and current mining activities, and thereby abate acid mine drainage from coal refuse piles, reclaim existing and idle or abandoned strip mines, and prevent uncontrolled air emissions caused by accidental burning of coal refuse piles, all at no cost to taxpayers.26 Id. at 3, JA___. By converting coal refuse into alternative energy, ARIPPA members are removing one of the principal sources of contamination to surface water and groundwater in coal mining regions of the United States, a long-term environmental benefit estimated to amount to billions of dollars. Id. Moreover, in the absence of continued operation of these ARIPPA facilities, the removal and clean-up of the remaining hundreds of millions of tons of coal refuse using traditional methods would perpetuate indefinitely, with the costs fully borne by taxpayers. Id. Due to the unique technical characteristics of circulating fluidized bed technology27 and the importance of preserving ash characteristics essential to the 26 In promulgating MATS, EPA itself recognized these benefits, acknowledging that “[u]nits that burn coal refuse provide multimedia environmental benefits by combining the production of energy with the removal of coal refuse piles and by reclaiming land for productive use. Consequently, because of the unique environmental benefits that coal refuse-fired EGUs provide, these units warrant special consideration ….” 76 Fed. Reg. at 25,066, JA___. Yet, EPA failed to consider the cost of these lost benefits in conducting its supplemental finding analysis. 27 Because EPA’s cost assessment in response to Michigan was limited to conventional coal- and oil-fired units, EPA also failed to consider the additional compliance costs associated with the unique technical and operational characteristics inherent in circulating fluidized bed design and operational configuration, including limitations on the technical and economic feasibility of both add-on emission systems 69 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 94 of 105 beneficial reuse of ash in mine reclamation,28 those ARIPPA circulating fluidized bed units firing bituminous coal refuse cannot satisfy the hydrogen chloride standard (or the SO2 surrogate) imposed by the MATS rule. Absent a revision to such standard, these plants will be forced to close and the environmental benefits they provide will be eliminated. Although ARIPPA specifically reminded EPA of these critical and substantial benefits in its comments, id. at 2-4, JA___-___, EPA failed to acknowledge or respond to these comments. EPA’s failure to consider the cost associated with the loss of these benefits as part of its Rule further confirms that EPA’s evaluation of the costs imposed by the MATS rule was unreasonable and inconsistent with the Supreme Court’s directive in Michigan. At bottom, EPA’s conclusion that “the record amply demonstrates that the advantages … for society … outweigh the disadvantages,” 81 Fed. Reg. at 24,429, JA___, depends on its refusal to consider every cost identified in the record other than EPA’s carefully selected system-wide “affordability” cost metrics. EPA cannot find advantages outweigh disadvantages unless EPA actually considers all of the relevant disadvantages. and sorbent injection strategies for reducing hydrogen chloride emissions. ARIPPA Comments at 9-18, JA___-___. 28 The continued ability to direct ash for beneficial use in mine reclamation, rather than dispose of the ash as a waste material, is not only central to the environmental benefits provided by these units, but also critical to the facilities’ continued financial viability. 70 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 95 of 105 CONCLUSION For the foregoing reasons, the petitions for review should be granted. Dated: November 18, 2016 Respectfully submitted, /s/ Makram B. Jaber F. William Brownell Makram B. Jaber Andrew D. Knudsen HUNTON & WILLIAMS LLP 2200 Pennsylvania Avenue, N.W. Washington, D.C. 20037 Tel: (202) 955-1500 Fax: (202) 778-2201 bbrownell@hunton.com mjaber@hunton.com aknudsen@hunton.com /s/ Neil D. Gordon Bill Schuette ATTORNEY GENERAL FOR THE PEOPLE OF MICHIGAN Aaron D. Lindstrom Solicitor General Neil D. Gordon Brian J. Negele Assistant Attorneys General ENRA Division 525 W. Ottawa Street P.O. Box 30755 Lansing, MI 48909 Tel: (515) 373-7540 Fax: (517) 373-1610 gordonn1@michigan.gov negeleb@michigan.gov Counsel for Petitioner Utility Air Regulatory Group Counsel for Petitioner Michigan Attorney General Bill Schuette, on behalf of the People of Michigan 71 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 96 of 105 /s/ Geoffrey K. Barnes Geoffrey K. Barnes J. Van Carson Wendlene M. Lavey John D. Lazzaretti Robert D. Cheren SQUIRE PATTON BOGGS (US) LLP 4900 Key Tower 127 Public Square Cleveland, OH 44114 Tel: (216) 479-8646 geoffrey.barnes@squirepb.com /s/ Robert D. Tambling Luther Strange ATTORNEY GENERAL OF ALABAMA Robert D. Tambling State of Alabama Office of the Attorney General 501 Washington Avenue Montgomery, AL 36130 Tel: (334) 242-7445 Fax: (334) 242-2433 Counsel for Petitioner Murray Energy Corporation /s/ Keith J. Miller Mark Brnovich ATTORNEY GENERAL OF ARIZONA John R. Lopez IV Solicitor General Keith J. Miller Assistant Solicitor General James T. Skardon Assistant Attorney General 1275 West Washington Street Phoenix, AZ 85007 Tel: (602) 542-3333 keith.miller@azag.gov /s/ Bart E. Cassidy Bart E. Cassidy Katherine L. Vaccaro MANKO, GOLD, KATCHER & FOX, LLP 401 City Avenue, Suite 901 Bala Cynwyd, PA 19004 Tel: (484) 430-5700 bcassidy@mankogold.com kvaccaro@mankogold.com Counsel for Petitioner State of Alabama Counsel for Petitioner ARIPPA Counsel for Petitioner State of Arizona /s/ Stacey Turner Stacey Turner SOUTHERN COMPANY SERVICES, INC. 600 18th Street North BIN 14N-8195 Birmingham, AL 35203 Tel: (205) 257-2823 staturne@southernco.com Counsel for Petitioner Southern Company Services, Inc. 72 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 /s/ C. Grady Moore, III C. Grady Moore, III BALCH & BINGHAM LLP 1901 Sixth Avenue North, Suite 1500 Birmingham, AL 35303-4642 Tel: (205) 226-8718 Fax: (205) 488-5704 gmoore@balch.com Page 97 of 105 /s/ Nicholas J. Bronni Leslie Rutledge ATTORNEY GENERAL OF ARKANSAS Lee Rudofsky Solicitor General Nicholas J. Bronni Deputy Solicitor General Office of the Attorney General 323 Center Street, Suite 200 Counsel for Petitioner Alabama Power Company Little Rock, AR 72201 Tel: (501) 682-8090 /s/ Angela J. Levin Angela J. Levin Counsel for Petitioner State of Arkansas TROUTMAN SANDERS LLP 580 California Street, Suite 1100 /s/ Jeffrey A. Chanay Derek Schmidt San Francisco, CA 94104 ATTORNEY GENERAL OF KANSAS Tel: (415) 477-5787 Jeffrey A. Chanay Fax: (415) 477-5710 Chief Deputy Attorney General angela.levin@troutmansanders.com Office of the Attorney General 120 S.W. 10th Avenue, 3rd Floor Margaret Claiborne Campbell Topeka, KS 66612-1597 TROUTMAN SANDERS LLP 600 Peachtree Street, NE, Suite 5200 Tel: (785) 368-8435 Atlanta, GA 30308-2216 jeff.chanay@ag.ks.gov Tel: (404) 885-3000 Fax: (404) 962-6521 Counsel for Petitioner State of Kansas margaret.campbell@troutmansanders.com Counsel for Petitioners Georgia Power Company and Southern Company Services, Inc. 73 USCA Case #16-1127 Document #1647029 /s/ Terese T. Wyly Terese T. Wyly BALCH & BINGHAM LLP 1310 Twenty Fifth Avenue Gulfport, MS 39501-1931 Tel: (228) 214-0413 Fax: (888) 897-6221 twyly@balch.com Counsel for Petitioner Mississippi Power Company Filed: 11/18/2016 Page 98 of 105 /s/ Mitchel T. Denham Andy Beshear ATTORNEY GENERAL OF KENTUCKY Mitchel T. Denham Assistant Deputy Attorney General Joseph A. Newberg, II Assistant Attorney General Kentucky Office of the Attorney General The Capitol Building 700 Capitol Avenue, Suite 118 Frankfort, KY 40601 Tel: (502) 696-5300 mitchel.denham@ky.gov joe.newberg@ky.gov Counsel for Petitioner Commonwealth of Kentucky /s/ Jeffrey A. Stone Jeffrey A. Stone BEGGS & LANE, RLLP 501 Commendencia Street Pensacola, FL 32502 Tel: (850) 432-2451 JAS@beggslane.com Robert A Manning Joseph A. Brown HOPPING GREEN & SAMS, P.A. 119 S. Monroe Street, Suite 300 Tallahassee, FL 32301 Tel: (850) 222-7500 Fax: (850) 224-8551 robertm@hgslaw.com josephb@hgslaw.com /s/ Justin D. Lavene Douglas J. Peterson ATTORNEY GENERAL OF NEBRASKA Dave Bydalek Chief Deputy Attorney General Justin D. Lavene Assistant Attorney General 2115 State Capitol Lincoln, NE 68509 Tel: (402) 471-2682 justin.lavene@nebraska.gov Counsel for Petitioner State of Nebraska Counsel for Petitioner Gulf Power Company 74 USCA Case #16-1127 Document #1647029 /s/ P. Stephen Gidiere III P. Stephen Gidiere III C. Grady Moore, III Julia B. Barber BALCH & BINGHAM LLP 1901 6th Ave. N., Suite 1500 Birmingham, AL 35203 Tel: (205) 251-8100 sgidiere@balch.com Stephanie Z. Moore Executive Vice President & General Counsel VISTRA ENERGY CORP. 1601 Bryan Street, 22nd Floor Dallas, TX 75201 Daniel J. Kelly Vice President and Associate General Counsel VISTRA ENERGY CORP. 1601 Bryan Street, 43rd Floor Dallas, TX 75201 Counsel for Petitioner Oak Grove Management Company LLC Filed: 11/18/2016 Page 99 of 105 /s/ Margaret Olson Wayne Stenehjem ATTORNEY GENERAL OF NORTH DAKOTA Margaret Olson Assistant Attorney General North Dakota Attorney General’s Office 500 North 9th Street Bismarck, ND 58501-4509 Tel: (701) 328-3640 Fax: (701) 328-4300 maiolson@nd.gov Counsel for Petitioner State of North Dakota /s/ Eric E. Murphy Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ohioattorneygeneral.gov Counsel for Petitioner State of Ohio 75 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 100 of 105 /s/ P. Clayton Eubanks E. Scott Pruitt ATTORNEY GENERAL OF OKLAHOMA P. Clayton Eubanks Deputy Solicitor General 313 N.E. 21st Street Oklahoma City, OK 73105 Tel: (405) 522-8992 Fax: (405) 522-0085 clayton.eubanks@oag.ok.gov fc.docket@oag.state.ok.us Counsel for Petitioner State of Oklahoma /s/ James Emory Smith, Jr. Alan Wilson ATTORNEY GENERAL OF SOUTH CAROLINA James Emory Smith, Jr. Deputy Solicitor General Office of the Attorney General P.O. Box 11549 Columbia, SC 29211 Tel: (803) 734-3680 esmith@scag.gov Counsel for Petitioner State of South Carolina 76 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 101 of 105 /s/ Mary E. Smith Ken Paxton ATTORNEY GENERAL OF TEXAS Jeffrey C. Mateer First Assistant Attorney General Brantley Starr Deputy First Assistant Attorney General James E. Davis Deputy Attorney General for Civil Litigation Priscilla M. Hubenak Chief, Environmental Protection Division Mary E. Smith Assistant Attorney General Office of the Attorney General of Texas Environmental Protection Division P.O. Box 12548, MC-066 Austin, TX 78711-2548 Tel: (512) 475-4041 Fax: (512) 320-0911 mary.smith@texasattorneygeneral.gov Counsel for Petitioners State of Texas, Texas Commission on Environmental Quality, Public Utility Commission of Texas, and Railroad Commission of Texas 77 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 102 of 105 /s/ Elbert Lin Patrick Morrisey ATTORNEY GENERAL OF WEST VIRGINIA Elbert Lin Solicitor General Counsel of Record State Capitol Building 1, Room 26-E Charleston, WV 25305 Tel: (304) 558-2021 Fax: (304) 558-0140 elbert.lin@wvago.gov Counsel for Petitioner State of West Virginia /s/ Misha Tseytlin Brad D. Schimel ATTORNEY GENERAL OF WISCONSIN Misha Tseytlin Solicitor General Counsel of Record Wisconsin Department of Justice 17 West Main Street Madison, WI 53707 Tel: (608) 267-9323 tseytlinm@doj.state.wi.us Counsel for Petitioner State of Wisconsin 78 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 103 of 105 /s/ James Kaste Peter K. Michael ATTORNEY GENERAL OF WYOMING James Kaste Deputy Attorney General Michael J. McGrady Senior Assistant Attorney General Elizabeth A. Morrisseau Assistant Attorney General Wyoming Attorney General’s Office 2320 Capitol Avenue Cheyenne, WY 82002 Tel: (307) 777-6946 Fax: (307) 777-3542 james.kaste@wyo.gov mike.mcgrady@wyo.gov elizabeth.morrisseau@wyo.gov Counsel for Petitioner State of Wyoming 79 USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 104 of 105 CERTIFICATE OF COMPLIANCE Pursuant to Rule 32(a)(7)(C) of the Federal Rules of Appellate Procedure and Circuit Rules 32(e)(1) and 32(e)(2)(C), I hereby certify that the foregoing Opening Brief of State and Industry Petitioners contains 17,884 words, as counted by a word processing system that includes headings, footnotes, quotations, and citations in the count, and therefore is within the word limit set by the Court. Dated: November 18, 2016 /s/ Makram B. Jaber Makram B. Jaber USCA Case #16-1127 Document #1647029 Filed: 11/18/2016 Page 105 of 105 CERTIFICATE OF SERVICE I hereby certify that, on this 18th day of November 2016, a copy of the foregoing Opening Brief of State and Industry Petitioners was served electronically through the Court’s CM/ECF system on all ECF-registered counsel. /s/ Makram B. Jaber Makram B. Jaber USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Oral Argument Not Yet Scheduled Page 1 of 86 No. 15-1385 (consolidated with 15-1392, 15-1490, 15-1491 & 15-1494) IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT MURRAY ENERGY CORPORATION, Petitioner, v. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, Respondent. ________________________________ On Petition for Review of Final Agency Action of the United States Environmental Protection Agency 80 FED. REG. 65,292 (OCT. 26, 2015) ________________________________ STATE PETITIONERS’ OPENING BRIEF Brad D. Schimel Mark Brnovich Misha Tseytlin John R. Lopez, IV Attorney General Solicitor General Counsel of Record Daniel P. Lennington WISCONSIN DEPARTMENT OF JUSTICE 17 W. Main Street Madison, WI 53707 (608) 267-9323 Counsel for the State of Wisconsin Attorney General Solicitor General Dominic E. Draye Deputy Solicitor General Counsel of Record Keith Miller OFFICE OF THE ATTORNEY GENERAL 1275 W. Washington Street Phoenix, AZ 85007 (602) 542-8255 Counsel for the State of Arizona Additional counsel listed on following pages USCA Case #15-1385 Document #1610107 Peter S. Glaser Carroll W. “Mack” McGuffey Darren W. Dwyer TROUTMAN SANDERS LLP 401 Ninth Street, N.W. Washington, D.C. 20004 (202) 274-2952 Counsel for the State of Arizona Filed: 04/22/2016 Page 2 of 86 Leslie C. Rutledge Attorney General Lee Rudofsky Solicitor General Counsel of Record Jamie L. Ewing Assistant Attorney General 323 Center Street Suite 200 Little Rock, AR 72201 (501) 682-2637 Counsel for the State of Arkansas Andy Beshear Jeff Landry Joseph A. Newberg, II Steven B. “Beaux” Jones Attorney General Attorney General Assistant Attorney General Counsel of Record Counsel of Record Duncan S. Kemp, IV Assistant Attorneys General KENTUCKY OFFICE OF THE ATTORNEY GENERAL The Capitol Building 700 Capitol Avenue, Suite 118 Frankfort, Kentucky 40601 (502) 696-5611 Louisiana Department of Justice 1185 North Third Street Baton Rouge, LA 70802 (225) 326-6085 Lara Katz Wayne Stenehjem Counsel for the Commonwealth of Kentucky Assistant General Counsel Counsel of Record 1190 St. Francis Drive Santa Fe, New Mexico 87505 (505) 827-2885 Counsel for New Environment Department Counsel for the State of Louisiana Attorney General Margaret I. Olson Assistant Attorney General Counsel of Record 500 North 9th Street Mexico Bismarck, ND 58501-4509 (701) 328-3640 Counsel for the State of North Dakota USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 E. Scott Pruitt Ken Paxton P. Clayton Eubanks Jeffrey C. Mateer Attorney General Deputy Solicitor General Counsel of Record 313 N.E. 21st St Oklahoma City, OK 73105 (405) 521-3921 Counsel for the State of Oklahoma Page 3 of 86 Attorney General First Assistant Attorney General Priscilla M. Hubenak Chief, Environmental Protection Division Matthew B. Miller Assistant Attorney General Counsel of Record Craig J. Pritzlaff Sean Reyes Attorney General Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL OF TEXAS Parker Douglas Chief Federal Deputy & General ENVIRONMENTAL PROTECTION Counsel DIVISION Counsel of Record P.O. Box 12548, MC-066 UTAH ATTORNEY GENERAL’S OFFICE Austin, TX 78711-2548 (512) 463-2012 350 North State Street, Ste. 230 Salt Lake City, UT 84114-2320 Counsel for the State of Texas (801) 538-9600 Counsel for the State of Utah USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 4 of 86 CERTIFICATE AS TO PARTIES, RULINGS & RELATED CASES Pursuant to Circuit Rule 28(a)(1), Petitioners state as follows: A. Parties, Intervenors, and Amici Curiae These cases involve the following parties: Petitioners: No. 15-1385: Murray Energy Corporation. No. 15-1392: State of Arizona; State of Arkansas; New Mexico Environment Department; State of North Dakota; and State of Oklahoma. No. 15-1490: Sierra Club; Physicians for Social Responsibility; National Parks Conservation Association; Appalachian Mountain Club; and West Harlem Environmental Action, Inc. No. 15-1491: Chamber of Commerce of the United States of America; National Association of Manufacturers; American Petroleum Institute; Utility Air Regulation Group; Portland Cement Association; American Coke and Coal Chemicals Institute; Independent Petroleum Association of America; National Oilseed Processors Association; and American Fuel & Petrochemical Manufacturers. i USCA Case #15-1385 No. 15-1494: Document #1610107 Filed: 04/22/2016 Page 5 of 86 State of Texas; and Texas Commission on Environmental Quality. Respondents: Respondents are the United States Environmental Protection Agency (in No. 15-1385) and the United States Environmental Protection Agency and Gina McCarthy, Administrator (in Nos. 15-1392, 15-1490, 15-1491, 15-1494). Intervenors and Amici Curiae: State of Wisconsin; Commonwealth of Kentucky; State of Utah; and State of Louisiana are Petitioner-Intervenors† American Lung Association; Natural Resources Defense Council; Physicians for Social Responsibility; Sierra Club; Utility Air Regulatory Group; National Association of Manufacturers; American Forest & Paper Association; Chamber of Commerce of the United States of America; American Chemistry Council; American Coke and Coal Chemicals Institute; American Petroleum Institute; Independent Petroleum Association of America; American Iron and Steel Institute; This Brief uses the term “State Petitioners” to refer collectively to the Petitioners in Nos. 15-1392 and 15-1494 as well as the State Intervenors. ii † USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 6 of 86 National Oilseed Processors Association; Portland Cement Association; American Wood Council; American Fuel & Petrochemical Manufacturers; and American Foundry Society are RespondentIntervenors. American Thoracic Society is amici curiae in support of Petitioners. Institute for Policy Integrity at New York University School of Law is amici curiae in support of Respondents. B. Rulings Under Review These consolidated cases involve final agency action of the United States Environmental Protection Agency titled, “National Ambient Air Quality Standards for Ozone,” and published on October 26, 2015, at 80 FR 65,292. C. Related Cases These consolidated cases have not previously been before this Court or any other court. Counsel is aware of no other related cases. iii USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 7 of 86 TABLE OF CONTENTS CERTIFICATE AS TO PARTIES, RULINGS & RELATED CASES........ i TABLE OF AUTHORITIES ..................................................................... vi GLOSSARY ............................................................................................xiii JURISDICTIONAL STATEMENT ........................................................... 1 ISSUES PRESENTED .............................................................................. 2 STATUTES AND REGULATIONS .......................................................... 3 INTRODUCTION ...................................................................................... 4 STATEMENT OF THE CASE .................................................................. 5 STANDARD OF REVIEW....................................................................... 14 SUMMARY OF THE ARGUMENT ........................................................ 15 STANDING ............................................................................................. 19 ARGUMENT ........................................................................................... 19 I. EPA’s Approach to Background Ozone Levels Caused by Uncontrollable Sources Violates the CAA. ............................................. 19 A. EPA Violated the CAA by Failing to Address Adequately the Peak Effect of Uncontrollable Emissions on Peak Days. ........ 20 B. EPA Violated the CAA by Impermissibly Adopting a NonTextual Limitation on Its Own Authority. .................................... 28 C. EPA’s Promised Enforcement Relief Measures Are Impractical and Misuse Portions of the CAA Intended for Exceptional Rather than Routine Events. ..................................... 33 1. The Relief Mechanisms Identified by EPA Do Not Adequately Address Uncontrollable Background Ozone. 34 iv USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 8 of 86 2. Where They Apply, the Relief Measures Are Inadequate Solutions to the Problem of Uncontrollable Background Ozone. ............................................................................... 41 II. Under EPA’s Construction of the Act, the NAAQS Review Process Would Lack an “Intelligible Principle.” .................................................. 44 III. EPA’s Reliance on a Single Clinical Study to Justify the New NAAQS Is Arbitrary and Capricious. ..................................................... 50 CONCLUSION ........................................................................................ 53 v USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 9 of 86 TABLE OF AUTHORITIES* Page(s) FEDERAL CASES Allen v. Wright, 468 U.S. 737 (1984) ............................................................................. 19 Alliance for Cannabis Therapeutics v. DEA, 930 F.2d 936 (D.C. Cir. 1991) ............................................................. 30 * Am. Farm Bureau Fed’n v. EPA, 559 F.3d 512 (D.C. Cir. 2009) ........................................... 14, 16, 21, 27 Am. Trucking Ass’ns v. EPA 175 F.3d 1027 (D.C. Cir. 1999) ............................................... 29, 45, 46 * Am. Trucking Ass’ns v. EPA, 283 F.3d 355 (D.C. Cir. 2002) ........................................... 14, 30, 31, 46 American Petroleum Institute v. Costle, 665 F.2d 1176 (D.C. Cir. 1981) ......................................... 30, 31, 32, 33 Citizens to Preserve Overton Park, Inc. v. Volpe, 401 U.S. 402 (1971) ............................................................................. 43 Cronin v. Browner, 90 F. Supp. 2d 364 (S.D.N.Y. 2000) .................................................... 13 FDIC v. Meyer, 510 U.S. 471 (1994) ............................................................................. 48 Field v. Clark, 143 U.S. 649 (1892) ............................................................................. 44 Gregory v. Ashcroft, 501 U.S. 452 (1991) ............................................................................. 29 Authorities on which Petitioners primarily rely are indicated with an asterisk. vi * USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 10 of 86 Home Box Office, Inc. v. FCC, 567 F.2d 9 (D.C. Cir. 1977) ..................................................... 16, 21, 27 J. W. Hampton, Jr. & Co. v. United States, 276 U.S. 394 (1928) ................................................................. 18, 44, 45 Lead Industries Association v. EPA, 647 F.2d 1130 (D.C. Cir. 1980) ..................................................... 31, 32 * Michigan v. EPA, 135 S. Ct. 2699 (2015) ................................................................ passim Mississippi v. EPA, 744 F.3d 1334 (D.C. Cir. 2013) ................................................... passim NLRB v. Brown, 380 U.S. 278 (1965) ............................................................................. 43 Sierra Club v. EPA, No. 13-cv-2809 (N.D. Cal. Apr. 30, 2014) ........................................... 13 * Util. Air Regulatory Grp. v. EPA, 134 S. Ct. 2427 (2014) ............................................................ 14, 17, 29 West Virginia v. EPA, 362 F.3d 861 (D.C. Cir. 2004) ............................................................. 19 * Whitman v. American Trucking Associations, 531 U.S. 457 (2001) .................................................................... passim CONSTITUTIONAL PROVISIONS U.S. Const., Article I, § 1 ......................................................................... 44 FEDERAL STATUTES 5 U.S.C. § 706(2)(A) ................................................................................. 14 * 42 U.S.C. § 7407(a) .......................................................................... passim 42 U.S.C. § 7407(d) .................................................................................... 6 42 U.S.C. § 7408(a)(1)................................................................................ 5 vii USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 11 of 86 42 U.S.C. § 7408(a)(2).......................................................................... 6, 18 42 U.S.C. § 7409(a)(2)................................................................................ 6 42 U.S.C. § 7409(b)(1).......................................................................... 5, 48 42. U.S.C. § 7409(b)(2)............................................................................... 5 42 U.S.C. § 7409(d) .................................................................................. 45 42 U.S.C. § 7409(d)(1)...................................................................... 5, 6, 47 42 U.S.C. § 7409(d)(2)(A)-(B)..................................................................... 6 42 U.S.C. § 7410(a) .............................................................................. 7, 19 42 U.S.C. § 7410(c) .................................................................................... 7 42 U.S.C. § 7471 ........................................................................................ 7 42 U.S.C. § 7501-09a ............................................................................... 19 42 U.S.C. § 7509(b)(1).............................................................................. 30 42 U.S.C. § 7509a(a) .......................................................................... 40, 42 42 U.S.C. § 7509a(b) .................................................................... 39, 41, 42 42 U.S.C. § 7511-15 ................................................................................. 19 42 U.S.C. § 7511a(a) .................................................................................. 7 42 U.S.C. § 7511a(a)(1)............................................................................ 42 42 U.S.C. § 7511a(a)(2)(C) ....................................................................... 42 42 U.S.C. § 7511a(h) ................................................................................ 38 42 U.S.C. § 7511a(h)(1) ........................................................................... 41 42 U.S.C. § 7607(b) .................................................................................... 1 42 U.S.C. § 7607(d)(9)(A)......................................................................... 14 viii USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 12 of 86 42 U.S.C. § 7619(b)(1)(A) ......................................................................... 35 42 U.S.C. § 7619(b)(1)(A)(iii) ................................................................... 36 42 U.S.C. § 7619(b)(1)(B) ......................................................................... 36 42 U.S.C. § 7619(b)(2).............................................................................. 35 REGULATIONS 40 C.F.R. § 50.14 ................................................................................. 3, 35 40 C.F.R. § 50.14(a)(1) ............................................................................. 35 40 C.F.R. § 50.14(c)(3)(iv)(C) ................................................................... 35 40 C.F.R. § 50.14(c)(3)(iv)(E) ................................................................... 35 40 C.F.R. § 50.19 ....................................................................................... 3 40 C.F.R. § 50.19(b) ....................................................................... 6, 21, 22 FEDERAL REGISTER 73 Fed. Reg. 16,436 (Mar. 27, 2008) ................................................. 11, 52 79 Fed. Reg. 75,242 (Dec. 17, 2014) .................................. 8, 37, 41, 43, 52 80 Fed. Reg. 65,292 (Oct. 26, 2015)................................................. passim 80 Fed. Reg. 72,840 (Nov. 20, 2015) ........................................................ 37 OTHER AUTHORITIES Ambient Standards Grp., U.S. Envtl. Prot. Agency, Policy Assessment for the Review of the Ozone National Ambient Air Quality Standards (2014) (“Policy Assessment”), Doc ID No. EPA-HQ-OAR-2008-0699-0404 .............................................. 24, 25, 37 Dana R. Bennett, Nevada Mining Association, Comment Letter on Proposed Rule, National Ambient Air Quality Standards for Ozone (March 17, 2015), Doc. ID No. EPA-HQ-OAR-2008-06993175 ............................................................................................... 36, 41 ix USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 13 of 86 Owen R. Cooper et al., Increasing Springtime Ozone Mixing Ratios in the Free Troposphere over Western North America, 463 Nature 344, 344-348 (2010), Doc. ID No. EPA-HQ-OAR2008-0699-4265 ............................................................................. 10, 36 Chris Emery et al., Regional and Global Modeling Estimates of Policy Relevant Background Ozone over the United States, 47 Atmospheric Env’t 206, 206–217 (2012), Doc. ID No. EPA-HQOAR-2008-0699-4294 ...................................................................... 9, 23 EPA Opposition Br., No. 13-cv-2809 (N.D. Cal. Feb. 25, 2014).............. 13 EPA’s Proposed National Ambient Air Quality Standards for Ozone: Hearing before the Subcomm. on Clean Air & Nuclear Safety of the S. Comm. on Env’t & Pub. Works, 113th Cong. 1516 (2014) (testimony of Ross Eisenberg, Vice President, National Association of Manufacturers), cited at Doc. ID No. EPA-HQ-OAR-2008-0699-3817 ............................................................ 8 Howard J. Feldman, American Petroleum Institute, Comments on National Ambient Air Quality Standards for Ozone Proposed Rule (March 17, 2015), Doc. ID No. EPA-HQ-OAR-2008-06992465 ..................................................................................................... 12 Meiyun Lin et al., Transport of Asian Ozone Pollution into Surface Air over the Western United States in Spring, 117 J. Geophysical Res. D00V07 (2012), Doc. ID No. EPA-HQ-OAR2008-0699-3148 ............................................................................. 9, 10 Meiyun Lin et al., Springtime High Surface Ozone Events over the Western United States: Quantifying the Role of Stratospheric Intrusions (“Lin Intrusions”), 117 J. Geophysical Res. D00V22 (2012), Doc. ID No. EPA-HQ-OAR-2008-0699-3148 ....... 10, 22, 25, 26 Eric C. Massey, Arizona Department of Environmental Quality, Comment Letter on Proposed Rule, National Ambient Air Quality Standards for Ozone (March 17, 2015), Doc. ID No. EPA-HQ-OAR-2008-0699-3176 ............................................................ 8 x USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 14 of 86 Eric C. Massey, Western States Air Resources Council, Comment Letter on Proposed Rule, National Ambient Air Quality Standards for Ozone (March 16, 2015) (“Westar Comment”), Doc. ID No. EPA-HQ-OAR-2008-0699-1990 ...................... 4, 21, 38, 39 Stephen F. Mueller & Jonathan W. Mallard, Contributions of Natural Emissions to Ozone and PM2.5 as Simulated by the Community Multiscale Air Quality (CMAQ) Model, 45 Envtl. Sci. & Tech.4817, 4817-4823 (2011), cited in Doc. ID No. EPAHQ-OAR-2008-0699-0405 ............................................................. 10, 25 Edward S. Schelegle et al., 6.6-Hour Inhalation of Ozone Concentrations from 60 to 87 Parts per Billion in Healthy Humans, 180 Am. J. Respiratory & Critical Care Med. 265, 265-72 (2009), Doc. ID No. EPA-HQ-OAR-2008-0699-0198 .. 12, 51, 52 Sonoma Technologies, Regional and Local Contributions to Peak Local Ozone Concentrations in Six Western Cities (2006), cited at Doc. ID No. EPA-HQ-OAR-2008-0699-1990 .................................. 23 Cathy Stepp, Wisconsin Department of Natural Resources, Comments on EPA’s Proposed National Ambient Air Quality Standards for Ozone (March 17, 2015), Doc. ID No. EPA-HQOAR-2008-0699-1646 .......................................................................... 14 U.S. Envtl. Prot. Agency, Background Ozone Workshop, https://www.epa.gov/sites/production/files/201603/documents/2016workshopslides.pdf (“Workshop Slides”) ............. 40 U.S. Envtl. Prot. Agency, The National Ambient Air Quality Standards: Tools for Addressing Background Ozone, https://www.epa.gov/sites/production/files/201510/documents/20151001_background_ozone.pdf (“Tools Fact Sheet”) ............................................................................................. 9, 19 xi USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 15 of 86 U.S. Envtl. Prot. Agency, Responses to Significant Comments on the 2014 Proposed Rule on the National Ambient Air Quality Standards for Ozone (2014), Doc. ID No. EPA-HQ-OAR-20080699-4309 ...................................................................................... 40, 48 Charles-Edward A. Winslow, The Cost of Sickness and the Price of Health (1951) ...................................................................................... 49 Wyoming Department of Environmental Quality, Exceptional Events (Apr. 19, 2016, 2:00 PM), deq.wyoming.gov/aqd/monitoring/resources/exceptional-events (“Wyoming DEQ”) ............................................................................... 41 Lin Zhang et al., Improved Estimate of the Policy-Relevant Background in the United States Using the GEOS-Chem Global Model with 1/2° x 2/3° Horizontal Resolution over North America, 45 Atmospheric Env’t 6769, 6769-6776 (2011). Doc. ID No. EPA-HQ-OAR-2008-0699-3148 .......................................... 9, 23 xii USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 16 of 86 GLOSSARY Agency United States Environmental Protection Agency CAA Clean Air Act CASAC Clean Air Scientific Advisory Committee EPA United States Environmental Protection Agency FIP Federal Implementation Plan FR Federal Register NAAQS National Ambient Air Quality Standard NASA National Aeronautics and Space Administration NOAA National Oceanographic and Atmospheric Administration O3 Ozone ppb Parts Per Billion SIP State Implementation Plan xiii USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 17 of 86 JURISDICTIONAL STATEMENT This case challenges the following final rule promulgated by the United States Environmental Protection Agency (EPA): “National Ambient Air Quality Standards for Ozone,” 80 FR 65,292 (October 26, 2015)) (the “Rule”). Petitioners filed their Petitions for Review under 42 U.S.C. § 7607(b) within 60 days of the Rule’s publication in the Federal Register, as required by the statute. pursuant to that provision. 1 This Court has jurisdiction USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 18 of 86 ISSUES PRESENTED‡ 1. Whether EPA violated the CAA by failing to address adequately the peak effect of uncontrollable sources on peak days, thus undermining States’ ability to meet their obligation for ensuring that “national primary and secondary ambient air quality standards will be achieved and maintained.” 42 U.S.C. § 7407(a). 2. Whether EPA’s construction of the Act fails to give meaning to the “intelligible principle” needed to avoid an unconstitutional delegation of legislative authority. 3. Whether EPA provided adequate scientific justification for a new NAAQS. The Intervenor and Petitioner States also incorporate by reference the Industry Petitioners’ argument that EPA has failed to provide a reasoned explanation for changing the conclusions it draws from the same basic scientific evidence considered in the prior NAAQS revision. ‡ 2 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 19 of 86 STATUTES AND REGULATIONS All applicable statutes are contained in the Brief for the Industry Petitioners; the applicable regulations, 40 C.F.R. §§ 50.14, 50.19, appear in the Addendum to this brief. 3 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 20 of 86 INTRODUCTION Sunland Park, NM, is a town of 15,000 people cornered between the New Mexico-Texas border to the east and the United States’ international border with Mexico to the south. It has no major industry and contributes just 3% of the precursor substances that form ozone in the Paso del Norte airshed. Westar Comment at 19, (JA__). Its larger neighbors—El Paso, TX and Juarez, Mexico—are close in proximity but unreachable by the policies adopted in New Mexico, or (in the case of Juarez) even Washington, DC. In fact, New Mexico is virtually powerless to reduce the concentration of ozone around Sunland Park, which arises overwhelmingly from sources beyond the State’s ability to control. Moreover, because the area abuts El Paso, it does not qualify for relief as a “rural transport area” under the Clean Air Act (CAA). Nor can it escape the Act’s heavy regulatory burdens by pointing to pollution generated in Juarez. Instead, through no fault of its own, the State of New Mexico will now face heavy federal regulations and the threat of punitive sanctions, including loss of highway funds, for failing to do the impossible. 4 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 21 of 86 The story of how Sunland Park’s attainment area became the target of regulations that New Mexico has no hope of satisfying begins with a legally flawed rule that fails to account for uncontrollable sources of ozone. By imposing an unachievable standard, the Rule has made it impossible for New Mexico and many other States to fulfill their “responsibility” for ensuring that “national primary and secondary ambient air quality standards will be achieved and maintained.” 42 U.S.C. § 7407(a). Any rule that ignores the States’ responsibility to “achieve[] and maintain[]” the standard violates the CAA and must be vacated. STATEMENT OF THE CASE A. The Clean Air Act and the NAAQS Program The Clean Air Act requires EPA to issue and, at pentannual intervals, review National Ambient Air Quality Standards (NAAQS) for air pollutants that meet certain criteria. 42 U.S.C. §§ 7408(a)(1), 7409(d)(1). EPA must set primary NAAQS that are, “in the judgment of the Administrator, . . . allowing an adequate margin of safety, [] requisite to protect the public health.” Id. § 7409(b)(1); see also id. § 7409(b)(2) (secondary NAAQS “requisite to protect public welfare”). 5 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 22 of 86 “‘Requisite’ means the NAAQS must be sufficient, but not more than necessary.” Mississippi v. EPA, 744 F.3d 1334, 1342 (D.C. Cir. 2013) (internal quotation omitted). Every five years, EPA must “complete a thorough review” of a NAAQS and “make such revisions . . . as may be appropriate.” 42 U.S.C. § 7409(d)(1). That process involves consultation with the Clean Air Scientific Advisory Committee (CASAC), id. § 7409(d)(2)(A)-(B), and publication of “air quality criteria” explaining the “latest scientific knowledge useful in indicating the kind and extent of all identifiable effects on public health or welfare,” id. §§ 7408(a)(2), 7409(a)(2). Once a NAAQS is set, EPA classifies each air quality control region as “attainment,” “nonattainment,” or “unclassifiable.” 42 U.S.C. § 7407(d). For ozone, these classifications are based on the “3-year average of the annual fourth-highest daily maximum 8-hour O3 concentration.” 40 C.F.R. § 50.19(b). Each State has “primary responsibility” for ensuring that “national primary and secondary ambient air quality standards will be achieved and maintained.” 42 U.S.C. § 7407(a) (emphasis added). After EPA sets or revises a NAAQS, the task then falls to the States to 6 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 23 of 86 propose state implementation plans (SIPs) for the “implementation, maintenance, and enforcement” of the new standard. Id. § 7410(a). If a State fails to provide a SIP or if the Administrator disapproves it, EPA may impose a federal implementation plan (FIP) of its own creation. Id. § 7410(c). Either way, nonattainment areas face a variety of regulations, including a census of all ozone-causing emissions and onerous permitting requirements for new sources. See, e.g., id. § 7511a(a) (listing requirements for “marginal” nonattainment areas). Even for areas designated as in attainment, the SIP must “contain emission limitations and such other measures as may be necessary . . . to prevent significant deterioration of air quality.” Id. § 7471. B. Background Ozone from Uncontrollable Sources Ground-level ozone (O3) forms through the interaction of sunlight with volatile organic compounds, mono-nitrogen oxides, and, over longer periods, methane and carbon monoxide as well. 80 FR 65,299 (JA__). These precursor compounds arise from various sources: human activities within a State, which that State can control; human activities outside a State, which that State cannot control; and natural sources that no one can control. Id. Given the prevalence of uncontrollable 7 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 24 of 86 sources of ozone and its precursors, ozone measurements “can be substantially influenced by sources that cannot be addressed by domestic control measures.” 80 FR 65,300 (JA__). EPA itself recognizes that background ozone can be significant, including “a non-de-minimis number” of locations where uncontrollable ozone levels can “exceed the [former] NAAQS (i.e., 75ppb).” 75,242 (JA__). 79 FR According to NOAA, Las Vegas will “exceed EPA’s proposed range of ozone NAAQS almost entirely due to background ozone.” Eisenberg Testimony at 15-16 (JA__). Similarly, in Cochise County, Arizona, EPA’s own models anticipate that uncontrollable background ozone will account for 90.7% of the allowable 70ppb. Massey Comment at 7, (JA__). Even if background alone does not exceed the standard and force an area into nonattainment, it can leave so little room for anthropogenic ozone that attainment is functionally impossible. See, e.g., 79 FR 75,382 (JA__) (explaining that background levels can “prevent attainment” where there are “few remaining opportunities for local emission reductions”). Here, multiple studies show background levels at or near the new standard of 70ppb. One study found that significant 8 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 25 of 86 uncontrollable events could raise background ozone levels to 60–75 ppb. Lin at 14, (JA__). Another recent study concluded that “[i]f the NAAQS is lowered in the 60–70 ppbv range, areas of the intermountain West will have little or no ability to reach compliance through North American regulatory controls.” Zhang at 6774. Yet another study found that background ozone could reach levels of 60–70ppb. Emery 206-17, (JA__). The issue of background ozone is particularly acute when dealing with peak effects of uncontrollable emissions on peak ozone days. Although some background sources are relatively constant producers, other sources are highly volatile and can produce significant spikes in ozone and its precursors. “Stratospheric intrusions,” for example—in which upper-atmosphere ozone descends to the surface, usually in connection with warm weather and high altitude—can dramatically increase ozone levels through no fault of the States or their industries. See Tools Fact Sheet at 4 (JA__). A recent study funded by NOAA found over a dozen intrusions during just three months, contributing as much as 20-40ppb to background ozone, and pushing eight-hour ozone 9 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 26 of 86 readings above the new NAAQS, sometimes as high as 86ppb. Lin Intrusions at 17, (JA__). Similarly, transport from foreign industry increases ground-level ozone and can cause spikes in ozone under certain conditions. As foreign industry has expanded, the United States has seen a corresponding increase in the share of its background ozone attributable to foreign sources. Cooper 344-48 (JA__) (“[T]ransported ozone pollution from Asia . . . is increasing by approximately 0.63ppb per year.”). One modeling study found that 49% of springtime ozone readings above 70ppb in the southwestern United States “would not have occurred” without Asian emissions. Lin at 14 (JA__). Wildfires and lightning also cause sudden increases in ozone levels. One modeling study found that lightning can add as much as 2530ppb and wildfires can add more than 50ppb. Mueller & Mallard 4817-23 (JA__). C. Recent NAAQS Revisions. The Industry Petitioners have provided an extensive summary of the recent NAAQS revisions, which reduce the primary and secondary standards to 70ppb. Indus. Pets. Br. 7-16. In particular, the Industry 10 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 27 of 86 Petitioners have traced the gradual ratcheting down of the ozone NAAQS—beginning at 120ppb, proceeding to 80, then 75, and now 70ppb—to the point that the current standard is colliding with background levels in many parts of the country. The Petitioner States adopt that summary but highlight several features of the key clinical study on which EPA relies. Unlike epidemiological studies that attempt to estimate the effects of ozone by studying respiratory illnesses in the general population, clinical studies control for the many other components of the atmosphere and isolate subjects’ responses to an increase in ozone. The availability of new clinical evidence was central to this Court’s affirmance of the 2008 NAAQS revision. Mississippi, 744 F.3d at 1343-44; see also id. at 1351 (“‘[T]he epidemiological studies are not themselves direct evidence of a causal link between exposure to O3 and the occurrence of health effects.’” (quoting 73 FR 16,479)); see also 80 FR 65,323 (JA__) (epidemiological evidence of health effects is “complicated by the presence of co-occurring pollutants or pollutant mixtures”). In 2008, EPA had before it a pair of clinical studies in which 30 participants were exposed to ozone concentrations of 60 and 80ppb. 11 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 28 of 86 Mississippi, 744 F.3d at 1349-50. At the lower concentration, just six of the participants experienced lung-function decrements of at least 10%. Id. at 1349-50. EPA concluded that this minor deviation from normal lung function did not justify lowering the NAAQS to 60ppb and instead settled on 75ppb as the level requisite to protect public health. Id. The current rulemaking cites two clinical studies and relies almost exclusively on one of them. Schelegle 265-72 (JA__). That study exposed 31 participants to over six hours of near-continuous activity in an environment of 72ppb ozone. It found that six of the 31 participants—almost exactly the same ratio that proved unpersuasive in 2008—reported (reversible) decrements of at least 10%. Id. at 269 (JA__); Feldman Comment at 4 (JA__). Even by EPA’s definition, decrements alone do not constitute an “adverse health effect.” They must appear “in combination with” respiratory symptoms. 65,330 (JA__). respiratory Although the study found some evidence of both symptoms and reduced uncorrelated across study participants. (JA__). 80 FR lung function, they were Id.; Feldman Comment at 4 EPA identified no other clinical evidence to support the existence of any harm to public health at levels below 80ppb. 12 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 29 of 86 In light of the paucity of new evidence, EPA took years to announce its latest revision to the standard. Seeking to compel the Agency to complete its rulemaking, several environmental organizations filed suit in the Northern District of California. Sierra Club v. EPA, No. 13-cv-2809 (N.D. Cal. Apr. 30, 2014). In its brief opposing the plaintiffs’ timeline, EPA argued that “‘[t]he public has a significant interest in ensuring that the government does not promulgate rules via a process that emphasizes expediency over quality and accuracy.’” EPA Opposition Br., No. 13-cv-2809, at 11-12 (N.D. Cal. Feb. 25, 2014) (quoting Cronin v. Browner, 90 F. Supp. 2d 364, 373 (S.D.N.Y. 2000)). The Agency countered the plaintiffs’ arguments for feasibility, stating that “[i]t is difficult to imagine a circumstance where an agency could not sign some sort of a flawed rule by any particular date; but promulgating a flawed rule does nothing to advance the goals of Congress.” Id. at 12. On April 30, 2014, the court ordered EPA to act on precisely the timeline plaintiffs requested, and EPA did just that. Finally, the Petitioner States add that the Rule irrationally lengthens ozone monitoring seasons for several States based upon ozone readings above 60ppb between 2010 and 2013. 80 FR 65,416 (JA__). 13 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 30 of 86 The Agency took this approach even for States that demonstrated that they never had a single reading above 70ppb in the last twenty years over the majority of the new monitoring period. Stepp Comment at 3-5 (JA__). STANDARD OF REVIEW An agency rule must be set aside if it is “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” 42 U.S.C. § 7607(d)(9)(A); accord 5 U.S.C. § 706(2)(A). While this Court considers challenges to NAAQS under the “same highly deferential standard of review that we use under the Administrative Procedure Act,” such challenges receive “a searching and careful inquiry into the underlying facts.” Am. Trucking Ass’ns v. EPA, 283 F.3d 355, 362 (D.C. Cir. 2002) (quotation omitted). Moreover, “[a]n agency’s failure adequately to consider a relevant and significant aspect of a problem may render its rulemaking arbitrary and capricious.” Am. Farm Bureau Fed’n v. EPA, 559 F.3d 512, 520 (D.C. Cir. 2009). In addition, “an agency interpretation that is inconsistent with the design and structure of the statute as a whole does not merit deference.” Util. Air Regulatory Grp. v. EPA, 134 S. Ct. 14 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 31 of 86 2427, 2442 (2014) (citation omitted). EPA, in particular, violates the CAA if it wrongly considers itself bound not to consider “relevant factors.” Michigan v. EPA, 135 S. Ct. 2699, 2706 (2015). SUMMARY OF THE ARGUMENT I. The Rule must be vacated because the Agency’s approach to the critical issue of background ozone violates the CAA. A. Under the CAA, States have the “primary responsibility” for ensuring that “national primary and secondary ambient air quality standards will be achieved and maintained.” 42 U.S.C. § 7407(a) (emphasis added). EPA’s failure to address adequately the indisputably relevant issue of the States’ ability to “achieve[]” the new NAAQS, and concomitant failure to provide an adequate response to significant public comments on this issue, is reason enough to vacate the Rule. Numerous commenters presented EPA with studies demonstrating that the peak effects of sources that the States cannot control, on peak days, will make compliance with the new standard unduly onerous, and sometimes impossible. Indeed, EPA’s own modeling illustrates the same problem. Yet, the Agency did not take account of this critical issue, instead choosing to focus on “average” and 15 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 “seasonal mean” impacts of uncontrollable sources. (JA__). Page 32 of 86 80 FR 65,328 This focus is unresponsive because nonattainment does not depend on averages, but instead requires just four exceedances per year. EPA’s analysis thus fails the basic requirement that an agency must address “significant aspect[s] of a problem,” Am. Farm Bureau, 559 F.3d at 520, and respond to all “significant” comments on this issue, Home Box Office, Inc. v. FCC, 567 F.2d 9, 35 & n.58 (D.C. Cir. 1977). The peak effects of uncontrollable sources on peak days will lead the Agency to impose burdensome pollution-control measures in areas where such measures have no potential to improve air quality or serve public health. This is the paramount problem with regard to the critical issue of background ozone, and EPA’s failure to address the problem requires that the Rule be vacated. B. EPA also violated the CAA by unlawfully limiting its consideration of the impact of background ozone from uncontrollable sources. See Michigan, 135 S. Ct. at 2706. The Agency took the position that it may only consider ozone from uncontrollable sources in selecting a standard from within a “range of values” that EPA has 16 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 33 of 86 already deemed “reasonable.” 80 FR 65,328 (JA__). This is contrary to the text of the CAA, which requires EPA to set NAAQS such that States can fulfill their “responsibility” that the standard be “achieved and maintained.” 42 U.S.C. § 7407(a). Since States have no legal or practical ability to control ozone from uncontrollable sources, EPA has a duty to consider fully such sources in setting the standard. EPA’s contrary position would permit (and perhaps require) the Agency to set standards that cannot be “achieved and maintained” by the States. This result is not only contrary to the text of the CAA, but would transform the NAAQS program in violation of the bedrock administrative law principle that an agency’s interpretation is unlawful if it is “inconsisten[t] with the design and structure of the statute as a whole.” UARG, 134 S. Ct. at 2442. C. Relying on the CAA’s provisions for enforcement-stage relief is no response to these defects. Provisions addressing “exceptional events” are ill-suited to addressing routine exceedances that will inevitably occur due to uncontrollable background ozone. Likewise, the Act’s limited measures for helping areas affected by rural transport and international pollution are intended for infrequent exceedances, as 17 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 34 of 86 demonstrated by the assumption that these areas should remain classified as nonattainment and subject to the corresponding burdens. More fundamentally, enforcement-stage relief measures require States to file onerous petitions with EPA, which the Agency may decline in its discretion. II. EPA’s construction of the CAA misapplies Whitman v. American Trucking Associations, 531 U.S. 457 (2001), to eschew any consideration that would halt the NAAQS for a “zero-threshold” pollutant at a level greater than zero. The Act offers several such “intelligible principles” to guide the Agency’s work. J. W. Hampton, Jr. & Co. v. United States, 276 U.S. 394, 409 (1928). Its references to “achieve[] and maintain[],” “requisite,” “appropriate,” and “public health” all indicate that EPA must consider the burden of a NAAQS that is unprecedentedly close to background levels. III. Finally, EPA failed to explain how the “latest scientific knowledge . . . on public health or welfare” justifies the new NAAQS. 42 U.S.C. § 7408(a)(2). This failure is apparent in the Agency’s excessive reliance on a single clinical study with significant limitations. 18 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 35 of 86 STANDING The Petitioner States have standing to challenge a Rule that requires them to revise their SIPs to comport with the new standard. 42 U.S.C. § 7410(a); see West Virginia v. EPA, 362 F.3d 861, 868 (D.C. Cir. 2004). EPA’s new standard also threatens to bring additional areas within the Petitioner States into nonattainment, which imposes an assortment of burdens. 42 U.S.C. §§ 7501-09a, 7511-15. As a result, the Petitioner States suffer an actual injury that is “fairly traceable” to the revised NAAQS and is likely to be redressed by a favorable decision. Allen v. Wright, 468 U.S. 737, 751 (1984). ARGUMENT I. EPA’s Approach to Background Ozone Levels Caused by Uncontrollable Sources Violates the CAA. The CAA provides that each State has “primary responsibility” for ensuring that “national primary and secondary ambient air quality standards will be achieved and maintained.” 42 U.S.C. § 7407(a) (emphasis added). As EPA has conceded, in carrying out this statutory duty, “states are not responsible for reducing emissions from background sources.” Tools Fact Sheet at 1 (JA__). In the Rule, EPA attempted to retreat partially from this necessary concession, arguing 19 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 36 of 86 that achievability is relevant to choosing a NAAQS level “within the range of reasonable values” that the Administrator identified, but forbidden when setting the “reasonable” range in the first place. 80 FR 65,328 (JA__). The Agency thereafter ignored this textually- indefensible distinction and sought to explain away the problem of uncontrollable ozone through a series of non sequitur arguments. There are two approaches that this Court could take to finding that EPA acted unlawfully in addressing the critical issue of background ozone from uncontrollable sources. The narrower approach is to declare that the Rule is unlawful because the Agency conceded that the “states are not responsible for reducing emissions from background sources,” see infra Part I.A, and then failed to explain adequately how the Rule’s new standard is consistent with that textually-mandated principle. Alternatively, and more broadly, this Court could definitively hold that EPA violated the CAA by casting aside concerns regarding “achiev[ability]” and vacate the Rule on that basis. See infra Part I.B. A. EPA Violated the CAA by Failing to Address Adequately the Peak Effect of Uncontrollable Emissions on Peak Days. 1. EPA has conceded that even under its own modeling, uncontrollable sources of ozone can make it harder—and, sometimes, 20 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 37 of 86 impossible—for States to attain EPA’s new NAAQS standard. 80 FR 65,436 (JA__). Because EPA has acknowledged that the impact of uncontrollable ozone is a relevant, significant consideration for purposes of this rulemaking, the Agency was duty-bound to address rationally all “significant aspect[s] of [this] problem,” Am. Farm Bureau, 559 F.3d at 520; State Farm, 463 U.S. at 43, and to respond to all “significant” comments on this issue, Home Box Office, 567 F.2d at 35 & n.58. Numerous commenters addressed the background ozone issue, raising the critical point that peak impacts from uncontrollable sources on days with peak ozone measurements make it difficult or impossible for States to “achieve,” 42 U.S.C. § 7407(a), the new NAAQS standard (the “peak/peak problem”). See, e.g., Westar Comment at 6, (JA__) (noting the “significant difference” between average data and “actual exceedances of the standard, which EPA acknowledges is more relevant from a regulatory standpoint”). The process for NAAQS nonattainment designations illustrates why EPA’s failure to address adequately the peak/peak problem is so consequential. 40 C.F.R. § 50.19(b). Every day during the monitoring 21 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 38 of 86 season, each site determines which eight-hour period has the highest average ozone reading, which then becomes the daily value. Id. Each area then determines the fourth-highest daily value in a given year. Id. Every year, the fourth-highest readings from the past three years are averaged to determine that year’s “design value,” which is compared to the NAAQS. Id. This process means that if uncontrollable sources cause high ozone readings even a few days per year, those infrequent peak readings will be sufficient to push an area out of attainment. The process thus magnifies—sometimes to the point of crowding out all other evidence—the peak effects of uncontrollable sources on peak days. 2. The administrative record unambiguously demonstrates that uncontrollable sources, at their peak, will make it difficult, and sometimes impossible, for States to meet EPA’s new NAAQS on peak ozone days. Multiple studies in the record demonstrate that uncontrollable sources will leave little to no room for U.S. manmade emissions at the new 70ppb NAAQS standard. One study, jointly funded by NOAA and NASA, found over a dozen instances in which ozone from stratospheric intrusions raised background levels to 60–75 ppb. 22 Lin Intrusions USCA Case #15-1385 (JA__). Document #1610107 Filed: 04/22/2016 Page 39 of 86 Another study estimated that the annual fourth-highest background ozone levels in the intermountain west are 50–60ppb. See Zhang 6769, 6770 (JA__). This study concluded that “if the NAAQS is lowered in the 60–70 ppb range, areas of the intermountain West will have little or no ability to reach compliance through North American regulatory controls.” JA__. A different study modeled background ozone and found that it could reach levels of 60–70 ppb. Emery 206, 216 (JA__). And another estimated that “background ozone concentrations . . . ranged from 47ppb to 68ppb at six western cities during ozone episodes.” Sonoma Technologies at 3-1 (JA__). Notably, many of these studies systematically underestimate the peak effects of uncontrollable sources of ozone on peak days because their models do not account for highly volatile events that can significantly impact ozone—such as wildfires, lightning, stratospheric intrusions, and unique meteorological conditions. See Zhang 6769, 6770 (JA__). EPA’s own modeling confirms the widespread nature of this peak/peak problem. Specifically, EPA’s model identified a substantial number of days where uncontrollable sources are at, near, or above the 23 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 40 of 86 70ppb standard, and where uncontrollable source effects are also at peak levels. Policy Assessment at 2A-25 (JA__) (internal box added).1 While EPA sought to downplay its model’s results as “infrequent events,” 80 FR 65,328 (JA__), EPA has no answer for the critical point that just a few high readings per year trigger a finding of nonattainment.2 Each dot in the red box represents at least one day where ozone exceeded 70ppb and where background ozone would have been at least 60ppb without any U.S. manmade emissions. 1 EPA also pointed to an alternative model (dubbed the “source apportionment” model), Policy Assessment at 2-14, which predicts fewer—although still some—exceedances resulting from uncontrollable 2 24 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 41 of 86 In addition, while EPA’s own modeling confirms the prevalence of the peak/peak problem, the Agency’s reasoning undercounts that problem in significant respects. As EPA concedes, its model “was not expressly developed to capture” events such as wildfires, lightning, stratospheric intrusions, and unique meteorological conditions, Policy Assessment at 2A-42 (JA__), even though EPA acknowledges that “the highest background episodic concentrations are typically associated with [these types of events],” Id. at 2A-14. For example, although EPA modeled wildfire emissions, the Agency admits that its model accounts only for “monthly‐average wildfire emissions which are not intended to capture discrete events.” Id. at 2A-8-9. And there is no indication that EPA’s model included any input for stratospheric intrusions, despite studies showing that these events can cause spikes as large as 40ppb. Lin Intrusions at 17 (JA__). Likewise, wildfires can add over 50ppb, Mueller & Mallard 4817-23 (JA__), lightning can add 30ppb, and unique meteorological conditions can cause Asian emissions to add up to 15ppb, ozone. This alternative significantly underestimates the peak effects of uncontrollable sources by classifying all ozone that is created by a combination of precursors emitted from both uncontrollable and controllable sources as controllable ozone. Id. at 2-16. 25 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 42 of 86 Lin Intrusions at 10 (JA__), beyond what they already contribute on an “average” day. 3. EPA’s primary response to this overwhelming record evidence demonstrating the peak/peak problem for the new 70ppb standard is to change the subject, focusing on the average effects of uncontrollable sources. For example, the Agency reports “seasonal mean” background levels of only 25-50ppb. 80 FR 65,328 (JA__); see also id. (attempting a similar sleight of hand for background levels on high-ozone days by “average[ing] over the entire U.S.”). But as explained above, States’ “responsibility” for ensuring that the new NAAQS “will be achieved and maintained,” 42 U.S.C. § 7407(a), flows from peak impacts—not averages. If the Agency’s attainment designations were based on seasonal-average ozone readings, then seasonal-average background concentrations would be relevant. As it stands, however, NAAQS designations depend on an area’s four worst days. It is disingenuous for EPA to cite average figures when promulgating a new NAAQS only to use specific 8-hour data when determining nonattainment. The legal ramification of this legerdemain is that the Agency has not addressed a “significant aspect of [the] 26 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 43 of 86 problem,” Am. Farm Bureau, 559 F.3d at 520, which arises not from averages, but from the peak effects of uncontrollable ozone on the relatively few days that determine an area’s design value. As a fallback to its “seasonal mean” response, the rulemaking briefly discusses the “average” effect of uncontrollable ozone sources on peak days. 80 FR 65,328 (JA__). This is not responsive to the problem commenters raised. The issue is not the average effect of uncontrollable sources of ozone on either average- or high-ozone days. Rather, the problem is peak effects of uncontrollable sources on peak ozone days. Given how NAAQS compliance is measured, these events are sufficiently common to make it difficult, or even impossible, for States to fulfill their “responsibility” for ensuring that the new 70ppb standard “will be achieved and maintained,” 42 U.S.C. § 7407(a). EPA provided no adequate answer for this significant problem, Am. Farm Bureau, 559 F.3d at 520, and failed to respond to “substantial” comments raising that issue, Home Box Office, 567 F.2d at 35 & n.58. The Rule is thus unlawful on this basis alone. 27 USCA Case #15-1385 B. Document #1610107 Filed: 04/22/2016 Page 44 of 86 EPA Violated the CAA by Impermissibly Adopting a NonTextual Limitation on Its Own Authority. The Agency also acted unlawfully because it narrowed its consideration of the critical issue of the new standard’s “achiev[ability]” in a manner unsupported by statutory text. 42 U.S.C. § 7407(a). In the Rule, EPA concluded that background ozone was relevant only to selecting the NAAQS level “within the range of reasonable values” the Administrator had already identified, but that background could not inform the selection of the “reasonable” range. 80 FR 65,328 (JA__). EPA thus recognizes that achievability is relevant but, without statutory justification, treats it as selectively relevant. The Agency’s non-textual narrowing of the NAAQS analysis violates the CAA. See Michigan, 135 S. Ct. at 2606-07 (EPA’s erroneous conclusion that a mandatory factor is “irrelevant” to a regulatory decision renders the rule unlawful). EPA’s claim that it had to consider background ozone only when selecting the NAAQS standard from “within the range of reasonable values” is unauthorized. As noted above, the CAA assigns to States the “primary responsibility” for ensuring that “national primary and secondary ambient air quality standards will be achieved and 28 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 45 of 86 maintained.” 42 U.S.C. § 7407(a). EPA’s reading of the CAA as making “achiev[ability]” relevant only for selecting the NAAQS standard from “within a range of reasonable values,” 80 FR 65,328 (JA__), is irreconcilable with this statutory text. Put another way, nothing in the statute’s expectation of “achiev[ability]” suggests that the concept should be ignored entirely in determining a “reasonable range,” but then reemerge when selecting from within that range. EPA’s error here is remarkably similar to the violation that the Supreme Court recently found fatal in Michigan. In that case, just as here, EPA ignored a mandatory consideration (there, costs; here, achievability) at the first step of its regulatory analysis, but said that it could consider the factor at a later step. See 135 S. Ct. at 2710-11. EPA’s position is also “inconsisten[t] with the design and structure of the statute as a whole,” UARG, 134 S. Ct. at 2442 (quotation omitted), and raises serious federalism concerns, Gregory v. Ashcroft, 501 U.S. 452, 460-61 (1991). Under EPA’s interpretation, if the Administrator selected a range that no State could meet “without action affirmatively extracting chemicals from nature,” Am. Trucking Ass’ns v. EPA (“ATA I”), 175 F.3d 1027, 1036 (D.C. Cir. 1999), opinion modified 29 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 46 of 86 on reh’g, 195 F.3d 4, aff'd in part, rev’d in part by Whitman, the Agency would be duty-bound to impose upon States a standard within that impossible range. States, having no ability to “achieve” the impossible, would then be subject to severe sanctions under the CAA, including loss of highway funds. 42 U.S.C. § 7509(b)(1). It is hornbook administrative law that “[i]mpossible requirements imposed by an agency are perforce unreasonable.” Alliance for Cannabis Therapeutics v. DEA, 930 F.2d 936, 940 (D.C. Cir. 1991). EPA’s claim that Congress instructed the Agency to require the impossible here—especially in a context that carries severe punishments for noncompliance—is not credible. In the Rule, EPA rested its argument on certain statements in American Trucking and American Petroleum Institute v. Costle, 665 F.2d 1176 (D.C. Cir. 1981). 80 FR 65,328 (JA__). These cases do not support the Agency’s position. First, in American Trucking, EPA had set the ozone NAAQS at 80ppb, in part because a 70ppb standard would be “too close to peak background levels.” 283 F.3d at 379. This Court rejected a challenge to the Agency’s reliance on the peak impacts of uncontrollable sources, explaining: “although relative proximity to peak background ozone 30 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 47 of 86 concentrations did not, in itself, necessitate a level of [80ppb], EPA could consider that factor when choosing among the three alternative levels.” Id. In the present case, the Agency inexplicably engrafted the word “only” into this holding, entirely changing the statement’s meaning: “[C]ourts have clarified that EPA may consider proximity to background concentrations . . . only in the context of considering standard levels within the [pre-determined] range.” 80 FR 65,328 (JA__) (citing Am. Trucking, 283 F.3d at 379) (emphasis added). But American Trucking never held that selecting a standard from within a “range” is the only situation in which EPA can consider proximity to background ozone concentrations, and the Agency’s attempt to suggest otherwise is incorrect. Second, this Court’s statement in American Petroleum that EPA “may not consider economic and technological feasibility in setting air quality standards,” and later reiteration of the same point, similarly does not support the Agency’s position. 665 F.2d at 1185 (quoting Lead Industries Association v. EPA, 647 F.2d 1130 (D.C. Cir. 1980)). American Petroleum first made this statement while responding to the specific argument raised by the American Petroleum Institute (API) 31 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 48 of 86 that the “costs of meeting [the new NAAQS]” were too high. Id. at 1184. As the Supreme Court explained in Whitman, 531 U.S. at 464, American Petroleum was merely one of several cases from this Court following the rule from Lead Industries that “economic considerations may play no part in the promulgation of ambient air quality standards.” When American Petroleum turned to the city of Houston’s objections that the new standard would be “impossible” for the city to meet because of “natural factors,” this Court noted that its prior response to API’s cost argument addressed this objection “in part.” 665 F.2d at 1185 (emphasis added). Another “part” of this Court’s answer to Houston’s argument, however, was that the Agency need not “tailor national regulations to fit each region or locale.” Id. The issue in the present case is entirely different. American Petroleum involved a single city asserting that it would not be able to meet the new standard, based primarily on concerns regarding the availability of emission-control technology. In the present case, the States argue that the new standard will make it extremely difficult, and sometimes impossible, for many of them to satisfy their statutory responsibility for ensuring that NAAQS “will be achieved and 32 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 49 of 86 maintained.” 42 U.S.C. § 7407(a). Given that the CAA imposed no such duty on the city of Houston, this Court’s rejection of the city’s arguments does not address the issues of statutory authority and achievability the States raise here. American Petroleum is also factually distinguishable because the current NAAQS is closer to the level of ozone from uncontrollable sources, and the role of foreigngenerated pollution has mushroomed during the intervening 35 years. C. EPA’s Promised Enforcement Relief Measures Are Impractical and Misuse Portions of the CAA Intended for Exceptional Rather than Routine Events. Tacitly acknowledging that it would be unlawful to hold States responsible for ozone levels that they cannot control, the Rule suggests that the States may qualify for limited relief at the enforcement stage. 80 FR 65,436 (JA__). The tools EPA has in mind, however, are limited in their applicability and, even where applicable, do not undo the burdens created by the new standard.3 Promulgating a rule that depends on enforcement relief is problematic in its own right, but that Of course, even if they were completely effective at responding to nonattainment resulting from uncontrollable background ozone, these mechanisms do not relieve EPA of its responsibility to engage in “reasoned decisionmaking” that addresses “all relevant factors.” Michigan, 135 S. Ct. at 2706; see supra Part I.A. 3 33 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 50 of 86 strategy becomes a basis for vacatur when the promised relief is illusory. 1. The Relief Mechanisms Identified by EPA Do Not Adequately Address Uncontrollable Background Ozone. EPA identifies three measures that it promises will provide relief for areas where background ozone levels approach or exceed the revised NAAQS: (1) areas that would be classified as nonattainment under the 70ppb standard due only to exceptional events could avoid that designation “through exclusion of data affected by [those] exceptional events;” (2) nonattainment areas that qualify as “rural transport areas” could avoid certain more stringent requirements applicable to higher classifications of nonattainment areas; and (3) nonattainment areas that qualify for the international transport provisions could escape their obligation “to demonstrate attainment” and to adopt “more than reasonable controls” on local stationary sources. 80 FR 65,436 (JA__). Behind all three of these measures are provisions of the CAA. Unsurprisingly, none of them creates an exception so malleable that it can allow an area to demonstrate compliance with a standard that is set at, near, or below background levels. 34 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 51 of 86 First, the CAA’s “exceptional events” provision tasks the Administrator with promulgating “regulations governing the review and handling of air quality monitoring data influenced by exceptional events.” 42 U.S.C. § 7619(b)(2). It defines an “exceptional event” as one that “is not reasonably controllable or preventable” and “is caused by human activity that is unlikely to recur at a particular location or a natural event.” Id. § 7619(b)(1)(A). In 2007, EPA announced a rule for excluding data based on the occurrence of an exceptional event. 40 C.F.R. § 50.14. The threshold is high. A State must show that a specific event “caused a specific air pollution concentration at a particular air quality monitoring location” and must establish “a clear causal relationship” between the event and the air-quality measurement at issue. (c)(3)(iv)(E). 40 C.F.R. §§ 50.14(a)(1), Moreover, the rule provides that an exceptional event cannot reflect “normal historical fluctuations, including background.” Id. § 50.14(c)(3)(iv)(C) (emphasis added). EPA also notes in the preamble to the revised NAAQS that exceptional events do not include “routine natural emissions from vegetation, microbes, animals, and lightning.” 80 FR 65,439 n.239 (JA__). 35 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 52 of 86 The reason the “exceptional events” provision does not encompass biological, meteorological and recurring anthropogenic events is that they are not exceptional, precisely because they are part of background conditions. As Harvard’s Daniel Jacob explains regarding a NAAQS of 70ppb, “[y]ou’re not talking about events anymore. You’re talking about the routine. . . . And at that point, I think the system is going to break.” Bennett Comment at 15 (JA__). The Act’s exclusion of truly exceptional events only underscores EPA’s failure to consider routine obstacles to achievability, in setting the NAAQS. Moreover, the exceptional events provision does not allow an area to exclude anthropogenic foreign emissions because it applies only to “an event caused by human activity that is unlikely to recur.” 42 U.S.C. § 7619(b)(1)(A)(iii) (emphasis added). As recognized by all parties, international transport is very likely to recur, and with increasing intensity. Cooper 344, 344-48 (JA__). The provision also excludes “stagnation of air masses,” “meteorological inversions,” and other meteorological events “involving high temperatures or lack of precipitation.” 42 U.S.C. § 7619(b)(1)(B). 36 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 53 of 86 EPA has recently proposed a revision to the exceptional events rule. 80 FR 72,840 (Nov. 20, 2015). Even if EPA finalizes a revised rule, regulations and new agency guidance cannot alter the statutory criteria.4 Chief among these are the CAA’s exclusion of recurring human-caused events and meteorological events that EPA recognizes are “the cause” of increased exceedances. Policy Assessment at 2-3 to 24. The only time EPA may consider these factors is in setting the NAAQS itself. At best, EPA peddles false hope in suggesting that it has the latitude to address background ozone through exceptional events regulations. At worst, the Agency has strategically refused to consider the impossibility of achieving its NAAQS rule while pointing to future enforcement-stage relief, only to claim later that its hands are tied by the statute. EPA promulgated the NAAQS before making revisions to its exceptional events rule. But States are already at work designating nonattainment areas in order to meet an October 1, 2016 deadline. 79 FR 75,354 (JA__). As a result, the subsequent issuance of a revised rule is of little benefit, a fact compounded by the proposed rule’s failure to address uncontrollable background ozone. For example, the revised rule would still exclude biological processes and lightning, as well as foreign anthropogenic emissions. 4 37 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 54 of 86 Second, the CAA’s provisions for rural transport areas fail to provide effective relief for nonattainment due to background. To begin with, designation as a rural transport area simply moves the area from one class of nonattainment to another, 42 U.S.C. § 7511a(h); it does not avoid the requirements applicable to all nonattainment areas. See infra Part II.B. Even that minor accommodation excludes huge swaths of the country. Under the statute, a rural transport area cannot contain sources that make a “significant contribution” to ozone concentrations and cannot include or be adjacent to a Metropolitan Statistical Area (“MSA”). 42 U.S.C. § 7511a(h). When applied to large counties in the West, these criteria render the rural transport provision a nullity. White Pine County, Nevada, for example, covers 9,000 square miles and has a tiny population of just 10,000 inhabitants. It nevertheless cannot qualify as a rural transport area because it is adjacent to the Salt Lake City MSA, which is itself approximately the size of New Jersey. Westar Comment at 15 (JA__). In fact, due to the size of western counties, the Salt Lake City MSA has the potential to disqualify 46,023 square miles—an area the size of Pennsylvania—from being classified as rural 38 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 55 of 86 transport areas. Similar disqualifications occur around Phoenix, Las Vegas, Denver, and El Paso. In Cochise County, Arizona, which cannot benefit from the rural transport rule because of its proximity to Tucson, EPA estimates that background ozone contributes 92% of that county’s design value. Westar Comment at 7 (JA__). The unlucky correspondence of large counties and high background ozone levels in western States means that the CAA’s rural transport provision is ineffective medicine to cure a NAAQS set at or near background levels. Third, the CAA’s international transport provisions authorize limited relief for nonattainment areas that can establish “to the satisfaction of the Administrator” that they would have met the NAAQS “but for emissions emanating from outside of the United States.” 42 U.S.C. § 7509a(b). Even where applicable, these provisions do not allow a State to avoid a nonattainment designation or even to obtain a lower nonattainment classification, see 80 FR 65,444 (JA__); they simply provide exemptions from a handful of nonattainment requirements. See infra Part II.B. Relief under these provisions is further illusory because they require the States to establish that international transport is the “but 39 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 56 of 86 for” cause of nonattainment. The issue of which party bears the burden is important because quantifying the amount of pollution carried from outside the United States is difficult. See Response to Comments at 343 (JA__) (“there is no way to definitively measure or validate these numbers”); Workshop Slides at 21 (JA__) (using a “surrogate” for internationally transported ozone to identify a wide range—between 0.1 and 0.7 ppb/year—of annual increase in ozone attributable to foreign sources). Furthermore, by requiring States to show that international transport is the “but for” cause of nonattainment, these provisions fail to provide relief for situations where multiple background sources contribute to nonattainment. By relying on these provisions to justify its rule, EPA attempts to duck its responsibility under the Act to take into account whether its NAAQS is achievable. Rather than the Agency “meet[ing] its obligation to explain and expose every step of its reasoning,” Mississippi, 744 F.3d at 1349 (quotation omitted), EPA’s reliance on Section 7509a is an impermissible attempt to impose on States the task of showing why achievability is impossible. The Act does not countenance this inversion of its relief measures. 40 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 57 of 86 2. Where They Apply, the Relief Measures Are Inadequate Solutions to the Problem of Uncontrollable Background Ozone. Common to all of the enforcement-stage “tools” is their dependence on EPA’s discretion. 42 U.S.C. § 7511a(h)(1) (“in the Administrator’s discretion”); 42 U.S.C. § 7509a(b) (“to the satisfaction of the Administrator”). The discretionary nature of this relief renders it onerous to request, uncertain to obtain, and nearly impossible to challenge if denied. Utah, for example, has invested 4,000 hours since 2008 preparing a dozen exceptional event demonstrations that EPA has denied. Bennett Comment at 15 (JA__). Other States, like Nevada, have concluded that they lack the resources necessary to prove an exceptional event. Id. Even if a State shoulders the immense cost and lodges a request, EPA concedes that “few” nonattainment areas have ever obtained relief. 79 FR 75,384 (JA__). This admission is consistent with the experience of Wyoming, which has filed 25 exceptional event applications since 2012; EPA has granted only one. Bennett Comment at 14 (JA__); Wyoming DEQ (JA__). The Agency also has discretion in recognizing rural transport areas and has designated only four such areas in history, none of them for the 8-hour ozone NAAQS. 80 FR 41 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 58 of 86 65,438 & n.235 (JA__). Finally, EPA also has unfettered discretion to decide whether a State has made the required “but for” showing to qualify for the international transport provisions. See 42 U.S.C. § 7509a(a). Because discretionary relief is uncertain, these tools do not provide the States any assurance that they will be able to fulfill their responsibility for ensuring that NAAQS be “achieved and maintained.” 42 U.S.C. § 7407(a). They are therefore no substitute for an achievable standard that addresses the issue of uncontrollable background ozone. Even under the best of circumstances—when States can devote resources to seeking relief and EPA agrees to the request—the relief provided is incomplete. A rural transport area, for example, must still complete a “comprehensive, accurate, current inventory of actual emissions from all sources,” and must still comply with the onerous New Source Review permitting process “for the construction and operation of each new or modified major stationary source.” 42 U.S.C. §§ 7511a(a)(1), 7511a(a)(2)(C). international transport Likewise, an area that satisfies the requirements obtains relief from three provisions of the CAA, 42 U.S.C. § 7509a(b), but remains a 42 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 59 of 86 “nonattainment” area and therefore faces mandatory emission control measures and must meet special emission reduction targets, 79 FR 75,384 (JA__). These “remedies” are no substitute for a proper NAAQS. Additionally, case-by-case discretionary relief creates obstacles for obtaining judicial review. Unlike the rulemaking at issue in this litigation, an EPA decision to deny relief under the foregoing mechanisms would take the form of an individual adjudication. In that posture, courts defer to the agency both on its fact-finding, see NLRB v. Brown, 380 U.S. 278, 292 (1965), and on the application of law to facts, see Citizens to Preserve Overton Park, Inc. v. Volpe, 401 U.S. 402, 416 (1971). In fact, none of the State Petitioners is aware of a case in which EPA denied relief under any of the three provisions and a court later reversed that decision. This extreme deference undermines EPA’s argument that potential enforcement-stage relief is a substitute for enacting an achievable standard in the first place. By attempting to channel objections to the impossibility of compliance through adjudications, EPA endeavors to stack the deck in its favor, all while maintaining that this mechanism is itself a reason for this Court to rubberstamp an unachievable NAAQS. 43 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 60 of 86 EPA cannot redeem a rule that is unlawful by pointing to statutory “tools” that are cumbersome, discretionary, and, in any event, cannot provide adequate relief. The CAA’s provisions for exceptional events and rural and international transport are supposed to apply under rare circumstances. This Court should not read these provisions to cannibalize the more foundational principles of their parent statute, including the requirement that NAAQS be “achiev[able].” EPA’s reliance on these relief measures as a justification for its failure to account for background ozone is arbitrary, capricious, and inconsistent with the Clean Air Act as a whole. II. Under EPA’s Construction of the Act, the NAAQS Review Process Would Lack an “Intelligible Principle.” Because Article I provides that “[a]ll legislative Powers herein granted shall be vested in a Congress of the United States,” U.S. Const., art. I, § 1, courts have insisted that Congress cannot delegate its legislative power. Field v. Clark, 143 U.S. 649, 692 (1892). So long as Congress provides “an intelligible principle” for an agency to follow, however, “such legislative action is not a forbidden delegation of legislative power.” J.W. Hampton, Jr., & Co. v. United States, 276 U.S. 394, 409 (1928). 44 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 61 of 86 In Whitman, the Supreme Court found an “intelligible” principle in the language of the Act itself—“requisite”—which the Court defined as “not lower or higher than is necessary.” 531 U.S. at 475-76. But for that “principle” to be truly “intelligible,” EPA must also apply it in a way that is intelligible. Otherwise, the principle identified by the Supreme Court in Whitman would dissolve in EPA’s semantics, which was precisely what concerned this Court in ATA I: For EPA to pick any non-zero level it must explain the degree of imperfection permitted. The factors that EPA has elected to examine for this purpose in themselves pose no inherent nondelegation problem. But what EPA lacks is any determinate criterion for drawing lines. It has failed to state intelligibly how much is too much. 175 F.3d at 1034. In short, while Whitman held that EPA cannot supply a principle missing from the statute, the more relevant question here is whether EPA has “conform[ed]” to, not merely restated and then ignored, the “intelligible” principles that Congress provided. See J.W. Hampton, 276 U.S. at 409. The new ozone NAAQS demonstrates how EPA’s current interpretation of Section 109(d) of the CAA, 42 U.S.C. § 7409(d), would in effect violate the nondelegation doctrine essential to the separation of powers embedded in the Constitution. 45 Specifically, EPA’s USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 62 of 86 interpretation ignores several ways that EPA could give meaning to the principle identified in Whitman, including (i) ensuring standards are achievable, (ii) explaining any departures from prior standards, and (iii) considering potential detriment to “public health” from a standard that is too low. EPA’s failure to give any true meaning to its invocation of Whitman has left EPA “free to pick any point between zero and a hair below the concentrations yielding London’s Killer Fog.” ATA I, 175 F.3d at 1037. EPA’s evaluation of the 1997 ozone standard—the standard at issue in Whitman—confirms that Whitman is not as infinitely malleable as EPA now suggests. In crafting the 1997 standard, EPA recognized that background levels provided a reasonable lower bound to the analysis, a concept this Court accepted as relevant in upholding EPA’s decision not to lower the standard to 70ppb. Am. Trucking, 283 F.3d at 379 (on remand after Whitman). Likewise, Judge Tatel, in dissenting from the initial panel decision that was overturned by Whitman, agreed with EPA that its decision was well-reasoned, in part because EPA “set the ozone level just above peak background concentrations.” 175 F.3d at 1061 (Tatel, J., dissenting in part). Thus, 46 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 63 of 86 at least one lower bound on EPA’s standard-setting authority was wellunderstood and real—EPA would not set a standard that could be violated by “uncontrollable natural levels of ozone;” that would be too low, and therefore not “requisite” under Whitman. Thus, in context, the holding in Whitman found an intelligible principle (“requisite . . . not lower or higher than is necessary”) and EPA gave that principle meaning and effect (a standard below peak background is too low). Here, in contrast, EPA has jettisoned that lower bound. EPA also appears to have abandoned any meaningful attempt to allow prior standards to serve as a lower bound, at least in cases where EPA cannot articulate a meaningful reason for contradicting its prior analysis. To be sure, the determination of a certain standard as “requisite” on one date does not make that assessment “sacrosanct . . . until every aspect of it is undermined.” Mississippi, 744 F.3d at 1343 (2013). However, EPA must nevertheless explain any direct contradiction of its prior analysis, id., and the decision to lower the standard itself must also be “appropriate,” 42 U.S.C. § 7409(d)(1). But when commenters pointed out that EPA itself agreed in 1997 that 47 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 64 of 86 70ppb would be too close to peak background levels, EPA’s only response was to claim that a standard of 65ppb would present an even greater concern. See Response to Comments at 350 (JA__). The failure to directly answer the question exposes EPA’s failure to conform to any “intelligible principle” in crafting the new standard. The same statutory provision cannot “intelligibly” mean that 70ppb was “lower … than . . . necessary” in 1997, due to peak background levels, but “appropriate” in spite of peak background levels in 2015, especially when peak background levels have only increased. Citing Whitman and other cases, EPA also ignores all cost considerations. But ignoring all costs fails to give full effect to the statute’s primary focus: “public health.” As noted in Whitman, the Act’s primary instruction governing NAAQS standards is not just that they be “requisite” in some undefined sense, but rather “requisite” to protect “public health.” 42 U.S.C. § 7409(b)(1) (emphasis added). Because “public health” is undefined, it must bear its “ordinary or natural meaning.” FDIC v. Meyer, 510 U.S. 471, 476 (1994). When Congress added the language “public health” in 1970, the authoritative public health treatise defined that concept as “preventing disease, prolonging 48 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 65 of 86 life, and promoting physical health and efficiency [through] the development of social machinery which will ensure to every individual in the community a standard of living adequate to the maintenance of health.” Winslow at 28 (emphasis added). At a minimum, costs imposed on industry and the States—the “social machinery” that EPA regulates—influence the “standard of living” in the community. Justice Breyer recognized this concept in his concurring opinion in Whitman, noting that “requisite” protection of public health should not “lead to deindustrialization” because “[p]reindustrial society was not a very healthy society.” Whitman, 531 U.S. at 496 (Breyer, J., concurring). Justice Breyer’s connection between a NAAQS’s impact on the economy and its ability to serve the public health is not limited to the word “requisite.” It is also present in the Act’s reference to “public health.” Recognizing this feature of the statutory language not only faithfully applies the law but also avoids a collision with the Constitution’s assignment of legislative power to Congress alone. Having eliminated “achievability,” unexplained contradictions of prior determinations, and “public health” as principled boundaries on how low a NAAQS should go, EPA has reduced the intelligible principle 49 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 66 of 86 identified in Whitman to a nullity, particularly for a “non-threshold” pollutant “that inflict[s] a continuum of adverse health effects at any airborne concentration greater than zero.” Whitman, 531 U.S. at 475. EPA’s application of Whitman thus results in a standard that has all the hallmarks of an unconstitutional delegation of authority—an unbounded, essentially legislative policy announcement of how low is too low. If EPA is truly so unfettered in its application of the Act, then a reevaluation of the constitutionality of Section 109(d) is warranted— this time (and for the first time) in the context of a standard that fully exposes EPA’s ability to interpret away whatever intelligible principle the Supreme Court identified in Whitman. III. EPA’s Reliance on a Single Clinical Study to Justify the New NAAQS Is Arbitrary and Capricious. The State Petitioners incorporate by reference the Industry Petitioners’ argument that EPA has arbitrarily “changed the conclusions it drew from the same basic scientific evidence” available in 2008. See Indus. Pet. Br. 36-41. To that convincing exposition, the States add only that the 2009 Schelegle study does not bear the weight EPA places on it. 50 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 67 of 86 EPA recognizes the weaknesses in the Schelegle study, noting that, as several commenters pointed out: (1) “lung function decrements and respiratory symptoms . . . were not correlated with each other;” (2) average “decrements observed following exposures below 75 ppb are small (e.g., < 10% . . .);” and (3) the lung-capacity limitations observed were “transient and reversible, do not interfere with daily activities, and do not result in permanent respiratory injury.” 80 FR 65,330. In response, EPA infers from the American Thoracic Society’s silence that ATS’s requirement of both decrements and symptoms “is not restricted to effects of a particular magnitude nor a requirement that individual responses be correlated.” Id. (emphasis added); see also id. (“Similarly, CASAC made no such qualification”). This position is unreasonable on both counts, regardless of whether EPA chooses to focus on average or individualized data. If focused on average data, Schelegle’s 6% average decrements fall well short of the 10% minimum that EPA requires. If individual data are controlling, meaning that six of the 31 study participants satisfy the 10% threshold, those six 51 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 68 of 86 individuals are not the same people who reported symptoms.5 EPA’s claim that CASAC does not expressly forbid bundling decrements from one person with symptoms from another is also inconsistent with the requirement of both decrements and symptoms before finding an “adverse health effect,” a concept that is necessarily tied to individual human bodies. The effect on individuals is, moreover, precisely the reason why EPA prioritizes controlled human-exposure studies over less reliable epidemiological evidence. Mississippi, 744 F.3d at 1343-44; 73 FR 16,479; 79 FR 75,288. Either way, EPA must explain its choice. It is arbitrary and capricious to rely on uncorrelated individual results and a too-low average decrement based on ATS’s failure to foreclose this particular portmanteau of unpersuasive data. Ultimately, the 2009 Schelegle study does not present any new information on the effects of ozone. Additionally, EPA has not offered a reasoned explanation for how the study’s predictable findings justify a lower NAAQS under the scientific framework the Agency itself Additionally, EPA would need to provide a non-arbitrary explanation for how this tiny group—six of 31 participants—is compelling evidence today, when six of 30 was unconvincing in 2008. 5 52 USCA Case #15-1385 endorses. Document #1610107 Filed: 04/22/2016 Page 69 of 86 It is arbitrary and capricious for EPA to dismiss the Schelegle study’s limitations in the manner it has. CONCLUSION EPA’s hastily-crafted ozone NAAQS imposes an unachievable standard, divorced from the scientific realities of background ozone. The Agency’s only response is to promise a partial accommodation that the statute limits in both applicability and degree of relief. This model of rulemaking does not accord with the Clean Air Act, which demands that NAAQS be achievable. To abandon that expectation and instead impose standards that would require cessation of human activity across large parts of the country is either an abuse of discretion or proof that EPA’s construction of the Act does not reflect an intelligible principle. This Court should vacate the Rule. 53 USCA Case #15-1385 Document #1610107 April 22, 2016 s/ Misha Tseytlin Brad D. Schimel Page 70 of 86 Respectfully Submitted, . Attorney General Misha Tseytlin Solicitor General Counsel of Record Daniel P. Lennington WISCONSIN DEPARTMENT OF JUSTICE 17 W. Main Street Madison, WI 53707 (608) 267-9323 Filed: 04/22/2016 Counsel for the State of Wisconsin s/ Dominic E. Draye Mark Brnovich . Attorney General John R. Lopez, IV Solicitor General Dominic E. Draye Deputy Solicitor General Counsel of Record Keith Miller OFFICE OF THE ATTORNEY GENERAL 1275 W. Washington Street Phoenix, AZ 85007 (602) 542-8255 dominic.draye@azag.gov Peter S. Glaser Carroll W. “Mack” McGuffey Darren W. Dwyer TROUTMAN SANDERS LLP 401 Ninth Street, N.W. Washington, D.C. 20004 (202) 274-2952 Counsel for the State of Arizona 54 USCA Case #15-1385 Document #1610107 s/ Lee Rudofsky Leslie C. Rutledge . Attorney General Filed: 04/22/2016 Page 71 of 86 s/ Joseph A. Newberg, II Andy Beshear . Attorney General Lee Rudofsky Joseph A. Newberg, II Jamie L. Ewing KENTUCKY OFFICE OF ATTORNEY GENERAL The Capitol Building 700 Capitol Avenue, Suite 118 Frankfort, Kentucky 40601 (502) 696-5611 THE s/ Lara Katz Lara Katz . Solicitor General Counsel of Record Assistant Attorney General Counsel of Record Assistant Attorney General 323 Center Street Suite 200 Little Rock, AR 72201 (501) 682-2637 Counsel for the State of Arkansas s/ Steven B. Jones Jeff Landry . Attorney General Steven B. “Beaux” Jones Counsel of Record Duncan S. Kemp, IV Assistant Attorneys General Louisiana Department of Justice 1185 North Third Street Baton Rouge, LA 70802 (225) 326-6085 Counsel for the Commonwealth of Kentucky Assistant General Counsel Counsel of Record 1190 St. Francis Drive Santa Fe, New Mexico 87505 (505) 827-2885 Counsel for New Mexico Environment Department Counsel for the State of Louisiana 55 USCA Case #15-1385 Document #1610107 s/ Margaret I. Olson Wayne Stenehjem Attorney General Margaret I. Olson . Page 72 of 86 s/ P. Clayton Eubanks E. Scott Pruitt . Attorney General P. Clayton Eubanks Assistant Attorney General Counsel of Record Deputy Solicitor General Counsel of Record 500 North 9th Street Bismarck, ND 58501-4509 (701) 328-3640 313 N.E. 21st St Oklahoma City, OK 73105 (405) 521-3921 Counsel for the State of North Dakota s/ Matthew B. Miller Ken Paxton Filed: 04/22/2016 Counsel for the State of Oklahoma . Attorney General Jeffrey C. Mateer First Assistant Attorney General Priscilla M. Hubenak Chief, Environmental Protection Division Matthew B. Miller Assistant Attorney General Counsel of Record Craig J. Pritzlaff Assistant Attorney General s/ Parker Douglas Sean Reyes . Attorney General Parker Douglas Chief Federal Deputy & General Counsel Counsel of Record UTAH ATTORNEY GENERAL’S OFFICE 350 North State Street, Ste. 230 Salt Lake City, UT 84114-2320 (801) 538-9600 Counsel for the State of Utah OFFICE OF THE ATTORNEY GENERAL OF TEXAS ENVIRONMENTAL PROTECTION DIVISION P.O. Box 12548, MC-066 Austin, TX 78711-2548 (512) 463-2012 Counsel for the State of Texas 56 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 73 of 86 CERTIFICATE OF COMPLIANCE 1. This brief complies with the type-volume limitation of Fed. R. App. P. 32(a)(7)(C) because this brief contains 9,639 words, excluding the parts of the brief exempted by Fed. R. App. P. 32(a)(7)(B)(iii). The total number of words contained in this brief and the Industry Petitioners’ Brief is fewer than 19,000, per this Court’s Order of March 9, 2016. 2. This brief complies with the typeface requirements of Fed. R. App. P. 32(a)(5) and the type style requirements of Fed. R. App. P. 32(a)(6) because this brief has been prepared in a proportionally spaced typeface using Microsoft Word 2010 in 14-point Century type. s/ Dominic E. Draye Dominic E. Draye . Deputy Solicitor General OFFICE OF THE ATTORNEY GENERAL 1275 W. Washington Street Phoenix, AZ 85007 (602) 542-8255 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 74 of 86 CERTIFICATE OF SERVICE I hereby certify that I electronically filed the foregoing with the Clerk of the Court for the United States Court of Appeals for the District of Columbia Circuit by using the appellate CM/ECF system on April 22, 2016. All participants in the case are registered CM/ECF users and will be served by the appellate CM/ECF system. s/ Dominic E. Draye Dominic E. Draye . Deputy Solicitor General OFFICE OF THE ATTORNEY GENERAL 1275 W. Washington Street Phoenix, AZ 85007 (602) 542-8255 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 75 of 86 Regulatory Addendum USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 76 of 86 INDEX 40 C.F.R. § 50.14……………………………………………………………….3 40 C.F.R. § 50.19……………………………………………………………….9 2 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 77 of 86 40 C.F.R. § 50.14 Treatment of air quality monitoring data influenced by exceptional events. (a) Requirements. (1) A State may request EPA to exclude data showing exceedances or violations of the national ambient air quality standard that are directly due to an exceptional event from use in determinations by demonstrating to EPA's satisfaction that such event caused a specific air pollution concentration at a particular air quality monitoring location. (2) Demonstration to justify data exclusion may include any reliable and accurate data, but must demonstrate a clear causal relationship between the measured exceedance or violation of such standard and the event in accordance with paragraph (c)(3)(iv) of this section. (b) Determinations by EPA. (1) EPA shall exclude data from use in determinations of exceedances and NAAQS violations where a State demonstrates to EPA's satisfaction that an exceptional event caused a specific air pollution concentration in excess of one or more national ambient air quality standards at a particular air quality monitoring location and otherwise satisfies the requirements of this section. (2) EPA shall exclude data from use in determinations of exceedances and NAAQS violations where a State demonstrates to EPA's satisfaction that emissions from fireworks displays caused a specific air pollution concentration in excess of one or more national ambient air quality standards at a particular air quality monitoring location and otherwise satisfies the requirements of this section. Such data will be treated in the same manner as exceptional events under this rule, provided a State demonstrates that such use of fireworks is significantly integral to traditional national, ethnic, or other cultural events including, but not limited to July Fourth celebrations which satisfy the requirements of this section. 3 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 78 of 86 (3) EPA shall exclude data from use in determinations of exceedances and NAAQS violations, where a State demonstrates to EPA's satisfaction that emissions from prescribed fires caused a specific air pollution concentration in excess of one or more national ambient air quality standards at a particular air quality monitoring location and otherwise satisfies the requirements of this section provided that such emissions are from prescribed fires that EPA determines meets the definition in § 50.1(j), and provided that the State has certified to EPA that it has adopted and is implementing a Smoke Management Program or the State has ensured that the burner employed basic smoke management practices. If an exceptional event occurs using the basic smoke management practices approach, the State must undertake a review of its approach to ensure public health is being protected and must include consideration of development of a SMP. (4) [Reserved] (c) Schedules and Procedures. (1) Public notification. (i) All States and, where applicable, their political subdivisions must notify the public promptly whenever an event occurs or is reasonably anticipated to occur which may result in the exceedance of an applicable air quality standard. (ii) [Reserved] (2) Flagging of data. (i) A State shall notify EPA of its intent to exclude one or more measured exceedances of an applicable ambient air quality standard as being due to an exceptional event by placing a flag in the appropriate field for the data record of concern which has been submitted to the AQS database. 4 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 79 of 86 (ii) Flags placed on data in accordance with this section shall be deemed informational only, and the data shall not be excluded from determinations with respect to exceedances or violations of the national ambient air quality standards unless and until, following the State's submittal of its demonstration pursuant to paragraph (c)(3) of this section and EPA review, EPA notifies the State of its concurrence by placing a concurrence flag in the appropriate field for the data record in the AQS database. (iii) Flags placed on data as being due to an exceptional event together with an initial description of the event shall be submitted to EPA not later than July 1st of the calendar year following the year in which the flagged measurement occurred, except as allowed under paragraph (c)(2)(iv) or (c)(2)(v) of this section. (iv) For PM2.5 data collected during calendar years 2004-2006, that the State identifies as resulting from an exceptional event, the State must notify EPA of the flag and submit an initial description of the event no later than October 1, 2007. EPA may grant an extension, if a State requests an extension, and permit the State to submit the notification of the flag and initial description by no later than December 1, 2007. (v) For lead (Pb) data collected during calendar years 2006-2008, that the State identifies as resulting from an exceptional event, the State must notify EPA of the flag and submit an initial description of the event no later than July 1, 2009. For Pb data collected during calendar year 2009, that the State identifies as resulting from an exceptional event, the State must notify EPA of the flag and submit an initial description of the event no later than July 1, 2010. For Pb data collected during calendar year 2010, that the State identifies as resulting from an exceptional event, the State must notify EPA of the flag and submit an initial description of the event no later than May 1, 2011. (vi) When EPA sets a NAAQS for a new pollutant or revises the NAAQS for an existing pollutant, it may revise or set a new schedule for flagging exceptional event data, providing initial data descriptions and providing detailed data documentation in AQS for the initial designations of areas for those NAAQS. Table 1 provides the schedule 5 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 80 of 86 for submission of flags with initial descriptions in AQS and detailed documentation. These schedules shall apply for those data which will or may influence the initial designation of areas for those NAAQS. EPA anticipates revising Table 1 as necessary to accommodate revised data submission schedules for new or revised NAAQS. Table 1—Schedule of Exceptional Event Flagging and Documentation Submission for Data To Be Used in Designations Decisions for New or Revised NAAQS NAAQS Pollutant/ standard/(level)/ promulgation date Event flagging Detailed Air quality data & initial documentation collected for description submission calendar year deadline deadline PM2.5/24-Hr Standard (35 µg/m3) Promulgated October 17, 2006 2004-2006 October 1, 2007 a June 18, 2009 a Ozone/8-Hr Standard (0.075 ppm) Promulgated March 12, 2008 June 18, 2009 a 200520072008 2009 60 days after the end of the calendar quarter in which the event occurred or February 5, 2010, whichever date 6 April 15, 2008. a June 18, 2009 a June 18, 2009 1 60 days after the end of the calendar quarter in which the event occurred or February 5, 2010, whichever date occurs first.b USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 81 of 86 occurs first b July 1, 2010 a NO2/1-Hour Standard (80-100 2008 2009 2010 July 1, 2010 a PPB, final level TBD) April 1, 2011 a SO 2/1-Hour Standard (50-100 20082009 2010 PPB, final level TBD) October 1, 2010 b October 1, 2010 b January 22, 2011 a January 22, 2011 a July 1, 2010 a June 1, 2011 b June 1, 2011 b June 1, 2011 b June 1, 2011 b 2011 60 days after the end of the calendar quarter in which the event occurred or March 31, 2012, whichever date occurs first b 60 days after the end of the calendar quarter in which the event occurred or March 31, 2012, whichever date occurs first. b These dates are unchanged from those published in the original rulemaking, or are being proposed elsewhere and are shown in this table for informational purposes—the Agency is not opening these dates for comment under this rulemaking. a b Indicates change from general schedule in 40 CFR 50.14. 7 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 82 of 86 Note:EPA notes that the table of revised deadlines only applies to data EPA will use to establish the final initial designations for new or revised NAAQS. The general schedule applies for all other purposes, most notably, for data used by EPA for redesignations to attainment. (3) Submission of demonstrations. (i) A State that has flagged data as being due to an exceptional event and is requesting exclusion of the affected measurement data shall, after notice and opportunity for public comment, submit a demonstration to justify data exclusion to EPA not later than the lesser of, 3 years following the end of the calendar quarter in which the flagged concentration was recorded or, 12 months prior to the date that a regulatory decision must be made by EPA. A State must submit the public comments it received along with its demonstration to EPA. (ii) A State that flags data collected during calendar years 2004-2006, pursuant to paragraph (c)(2)(iv) of this section, must adopt the procedures and requirements specified in paragraph (c)(3)(i) of this section and must include a demonstration to justify the exclusion of the data not later than the submittal of the Governor's recommendation letter on nonattainment areas. (iii) A State that flags Pb data collected during calendar years 20062009, pursuant to paragraph (c)(2)(v) of this section shall, after notice and opportunity for public comment, submit to EPA a demonstration to justify exclusion of the data not later than October 15, 2010. A State that flags Pb data collected during calendar year 2010 shall, after notice and opportunity for public comment, submit to EPA a demonstration to justify the exclusion of the data not later than May 1, 2011. A state must submit the public comments it received along with its demonstration to EPA. (iv) The demonstration to justify data exclusion shall provide evidence that:(A) The event satisfies the criteria set forth in 40 CFR 50.1(j);(B) There is a clear causal relationship between the measurement under consideration and the event that is claimed to have affected the air quality in the area;(C) The event is associated with a measured concentration in excess of normal historical fluctuations, including background; and(D) There would have been no exceedance or violation but for the event. 8 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 83 of 86 (v) With the submission of the demonstration, the State must document that the public comment process was followed. [72 FR 13580, Mar. 22, 2007; 72 FR 28612, May 22, 2007; 73 FR 67051, Nov. 12, 2008; 74 FR 70598, Nov. 21, 2008; 74 FR 23312, May 19, 2009; 75 FR 6531, Feb. 9, 2010; 75 FR 35592, June 22, 2010] 40 C.F.R. § 50.19 Categorical exclusions not subject to the Federal laws and authorities cited in § 50.4. (a) General. The activities and related approvals of policy documents listed in paragraphs (b) and (c) of this section are not subject to the individual compliance requirements of the Federal laws and authorities cited in § 50.4, unless otherwise indicated below. These activities and approvals of policy documents are also categorically excluded from the EA required by NEPA except in extraordinary circumstances (§ 50.20(b)). HUD approval or implementation of these categories of activities and policy documents does not require environmental review, because they do not alter physical conditions in a manner or to an extent that would require review under NEPA or the other laws and authorities cited at § 50.4. (b) Activities. (1) Environmental and other studies, resource identification and the development of plans and strategies. (2) Information and financial advisory services. (3) Administrative and management expenses. (4) Public services that will not have a physical impact or result in any physical changes, including but not limited to services concerned with employment, crime prevention, child care, health, drug abuse, education, counseling, energy conservation and welfare or recreational needs. (5) Inspections and testing of properties for hazards or defects. (6) Purchase of insurance. (7) Purchase of tools. 9 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 84 of 86 (8) Engineering or design costs. (9) Technical assistance and training. (10) Assistance for temporary or permanent improvements that do not alter environmental conditions and are limited to protection, repair or restoration activities necessary only to control or arrest the effects from disasters or imminent threats to public safety including those resulting from physical deterioration. (11) Tenant-based rental assistance. (12) Supportive services including, but not limited to, health care, housing services, permanent housing placement, day care, nutritional services, short-term payments for rent/mortgage/utility costs, and assistance in gaining access to local, State, and Federal government benefits and services. (13) Operating costs including maintenance, security, operation, utilities, furnishings, equipment, supplies, staff training and recruitment and other incidental costs; however, in the case of equipment, compliance with § 50.4(b)(1) is required. (14) Economic development activities, including but not limited to, equipment purchase, inventory financing, interest subsidy, operating expenses and similar costs not associated with construction or physical expansion of existing facilities; however, in the case of equipment purchase, compliance with § 50.4(b)(1) is required. (15) Activities to assist homebuyers to purchase existing dwelling units or dwelling units under construction, including closing costs and downpayment assistance, interest buydowns, and similar activities that result in the transfer of title. (16) Housing pre-development costs including legal, consulting, developer and other costs related to site options, project financing, administrative costs and fees for loan commitments, zoning approvals, and other related activities which do not have a physical impact. (17) HUD's insurance of one-to-four family mortgages under the Direct Endorsement program, the insurance of one-to-four family mortgages under the Lender Insurance program, and HUD's guarantee of loans for one-to-four family dwellings under the Direct Guarantee procedure for the Indian Housing loan guarantee program, without any HUD review or approval before the completion of construction or rehabilitation and the loan closing; and HUD's acceptance for insurance of loans insured 10 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 85 of 86 under Title I of the National Housing Act; however, compliance with §§ 50.4(b)(1) and (c)(1) and 24 CFR 51.303(a)(3) is required. (18) HUD's endorsement of one-to-four family mortgage insurance for proposed construction under Improved Area processing; however, the Appraiser/Review Appraiser Checksheet (Form HUD-54891) must be completed. (19) Activities of the Government National Mortgage Association under Title III of the National Housing Act (12 U.S.C. 1716 et seq.). (20) Activities under the Interstate Land Sales Full Disclosure Act (15 U.S.C. 1701 et seq.).(21) Refinancing of HUD-insured mortgages that will not allow new construction or rehabilitation, nor result in any physical impacts or changes except for routine maintenance; however, compliance with § 50.4(b)(1) is required. (22) Approval of the sale of a HUD-held mortgage. (23) Approval of the foreclosure sale of a property with a HUD-held mortgage; however, appropriate restrictions will be imposed to protect historic properties. (24) HUD guarantees under the Loan Guarantee Recovery Fund Program (24 CFR part 573) of loans that refinance existing loans and mortgages, where any new construction or rehabilitation financed by the existing loan or mortgage has been completed prior to the filing of an application under the program, and the refinancing will not allow further construction or rehabilitation, nor result in any physical impacts or changes except for routine maintenance; however, compliance with §§ 50.4 (b)(1) and (c)(1) and 51.303(a) is required. (c) Approval of policy documents. (1) Approval of rules and notices proposed for publication in the Federal Register or other policy documents that do not:(i) Direct, provide for assistance or loan and mortgage insurance for, or otherwise govern or regulate, real property acquisition, disposition, leasing (other than tenant-based rental assistance), rehabilitation, alteration, demolition, or new construction; or (ii) Establish, revise, or provide for standards for construction or construction materials, manufactured housing, or occupancy. (2) Approval of policy documents that amend an existing document where the existing document as a whole would not fall within an exclusion in this paragraph (c) but the amendment by itself would do so; 11 USCA Case #15-1385 Document #1610107 Filed: 04/22/2016 Page 86 of 86 (3) Approval of policy documents that set out fair housing or nondiscrimination standards or enforcement procedures or provide for assistance in promoting or enforcing fair housing or nondiscrimination; (4) Approval of handbooks, notices and other documents that provide operating instructions and procedures in connection with activities under a Federal Register document that has previously been subject to a required environmental review. (5) Approval of a Notice of Funding Availability (NOFA) that provides funding under, and does not alter any environmental requirements of, a regulation or program guideline that was previously published in the Federal Register, provided that(i) The NOFA specifically refers to the environmental review provisions of the regulation or guideline; or(ii) The regulation or guideline contains no environmental review provisions because it concerns only activities listed in paragraph (b) of this section. (6) Statutorily required and/or discretionary establishment and review of interest rates, loan limits, building cost limits, prototype costs, fair market rent schedules, HUD-determined prevailing wage rates, income limits and exclusions with regard to eligibility for or calculation of HUD housing assistance or rental assistance, and similar rate and cost determinations and related external administrative or fiscal requirements or procedures which do not constitute a development decision that affects the physical condition of specific project areas or building sites. [61 FR 50916, Sept. 27, 1996, as amended at 62 FR 15802, Apr. 2, 1997; 63 FR 48990, Sept. 11, 1998; 68 FR 56127, Sept. 29, 2003] 12 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 ORAL ARGUMENT NOT YET SCHEDULED Page 1 of 55 No. 15-1166 (and consolidated cases) ______________________________________ IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT _______________________________________ WALTER COKE, INC., et al., Petitioners, V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, et al., Respondents. On Petition for Review of Final Agency Action of the United States Environmental Protection Agency 80 Fed. Reg. 33,840 (June 12, 2015) OPENING BRIEF OF STATE PETITIONERS Pamela Jo Bondi ATTORNEY GENERAL OF FLORIDA Jonathan L. Williams Jordan E. Pratt Deputy Solicitors General Jonathan A. Glogau Chief, Complex Litigation Office of the Attorney General PL-01, The Capitol Tallahassee, FL 32399 Tel: (850) 414-3300 Fax: (850) 410-2672 jonathan.williams@myfloridalegal.com Dated: March 16, 2016 Counsel for Petitioner State of Florida Additional counsel listed on signature block USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 2 of 55 CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES The Court consolidated the following cases for review: 15-1166, 15-1216, 15-1239, 15-1243, 15-1256, 15-1265, 15-1266, 15-1267, 15-1268, 15-1270, 15-1271, 15-1272, 15-1300, 15-1301, 15-1302, 15-1308 (A) Parties, Intervenors, and Amici Petitioners Alabama Power Company Big Brown Power Company, LLC BCCA Appeal Group Commonwealth of Kentucky Environmental Committee of the Florida Electric Power Coordinating Group, Inc. Georgia Coalition for Sound Environmental Policy Georgia Industry Environmental Coalition Georgia Power Company Gulf Power Company Luminant Generation Company, LLC Mississippi Power Company North Carolina Department of Environment and Natural Resources Oak Grove Management Company, LLC Sandow Power Company, LLC Southern Company Services, Inc. Southern Power Company SSM Litigation Group State of Alabama State of Arizona State of Arkansas State of Delaware State of Florida State of Georgia State of Kansas State of Louisiana State of Mississippi State of Missouri State of Ohio State of Oklahoma State of South Carolina i USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 3 of 55 State of South Dakota State of Tennessee State of Texas State of West Virginia Texas Commission on Environmental Quality Texas Oil and Gas Association Union Electric Company d/b/a Ameren Missouri Utility Air Regulatory Group Respondent Gina McCarthy, Administrator, United States Environmental Protection Agency United States Environmental Protection Agency Intervenors for Respondent Citizens for Environmental Justice Environmental Integrity Project Natural Resources Defense Council People Against Neighborhood Industrial Contamination Sierra Club (B) Rulings Under Review All of the petitions for review challenge EPA’s final rule entitled “State Implementation Plans: Responses to Petitions for Rulemaking, Restatement and Update of EPA’s SSM Policy Applicable to SIPs; Findings of Substantial Inadequacy; and SIP Calls To Amend Provisions Applying to Excess Emissions During Periods of Startup, Shutdown and Malfunction; Final Rule,” 80 Fed. Reg. 33840 (June 12, 2015). ii USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 4 of 55 TABLE OF CONTENTS CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES ................. i TABLE OF CONTENTS ................................................................................................... iii TABLE OF AUTHORITIES .............................................................................................. v GLOSSARY ........................................................................................................................... ix JURISDICTIONAL STATEMENT ................................................................................... 1 STATEMENT OF THE ISSUES ....................................................................................... 1 INTRODUCTION................................................................................................................ 2 STATUTES AND REGULATIONS ................................................................................. 3 STATEMENT OF THE CASE .......................................................................................... 3 I. THE SIP PROGRAM OF THE CLEAN AIR ACT ................................................. 3 II. REGULATION OF SSM PERIODS ...................................................................... 6 III. THE SIP CALL .................................................................................................... 8 SUMMARY OF THE ARGUMENT ................................................................................. 9 STANDING ......................................................................................................................... 11 STANDARD OF REVIEW ............................................................................................... 11 ARGUMENT ....................................................................................................................... 12 I. EPA HAS NOT PROPERLY FOUND THAT ANY SIP IS SUBSTANTIALLY INADEQUATE. .................................................................... 12 II. EVEN IF EPA PROPERLY INTERPRETED ITS SIP CALL AUTHORITY, IT MISINTERPRETED THE ACT’S REQUIREMENTS AND SIPS. ................................................................................................................ 22 A. EPA’s Decision to Ignore “General Duty” Requirements Violates the Act. ................................................................................. 22 iii USCA Case #15-1166 Document #1604344 TABLE OF CONTENTS – cont’d III. Filed: 03/16/2016 Page 5 of 55 B. EPA Incorrectly Interpreted SIPs As Containing Automatic Exemptions During SSM Periods. ............................... 24 C. EPA Incorrectly Determined That Director’s Discretion Provisions Violate the Act. ............................................................... 28 D. The Act Permits States to Include Affirmative Defenses in SIPs. ..................................................................................................... 34 EPA CANNOT CALL SIPS FOR REASONS IT DID NOT CLAIM CONSTITUTED SUBSTANTIAL INADEQUACIES. ........................................... 37 CONCLUSION ................................................................................................................... 38 CERTIFICATE OF COMPLIANCE .............................................................................. 44 CERTIFICATE OF SERVICE ......................................................................................... 45 iv USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 6 of 55 TABLE OF AUTHORITIES Cases Council for Urological Interests v. Burwell, 790 F.3d 212 (D.C. Cir. 2015) ........................................................................................ 37 Cty. of L.A. v. Shalala, 192 F.3d 1005 (D.C. Cir. 1999) ...................................................................................... 12 Fla. Power & Light Co. v. Costle, 650 F.2d 579 (5th Cir. 1981) ........................................................................................... 20 Luminant Generation Co. v. EPA, 714 F.3d 841 (5th Cir. 2013) ........................................................................ 18, 28, 35, 37 Nat’l Ass’n of Clean Air Agencies v. EPA, 489 F.3d 1221 (D.C. Cir. 2007) ...................................................................................... 11 NRDC v. EPA, 749 F.3d 1055 (D.C. Cir. 2014) ....................................................... 5, 7, 8, 10, 18, 35, 36 Texas v. EPA, 690 F.3d 670 (5th Cir. 2012) ...............................................................................23, 28, 37 Train v. NRDC, 421 U.S. 60 (1975) .............................................................................................................. 5 US Magnesium, LLC v. EPA, 690 F.3d 1157 (10th Cir. 2012)....................................................................................... 19 Virginia v. EPA, 108 F.3d 1397 (D.C. Cir. 1997) .............................................................................. 4, 5, 15 West Virginia v. EPA, 362 F.3d 861 (D.C. Cir. 2004) ........................................................................................ 11 Whitman v. Am. Trucking Ass’n, 531 U.S. 457, 473 (2001) ................................................................................................... 4 Statutes CAA § 107, 42 U.S.C. § 7407 ................................................................................................ 4 v USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 7 of 55 CAA § 109, 42 U.S.C. § 7409 ............................................................................................ 3, 4 CAA § 110, 42 U.S.C. § 7410 .…..1, 2, 4, 5, 6, 8, 9, 10, 12, 13, 14, 16, 19, 24, 29, 33, 34, 35, 36 CAA § 111, 42 U.S.C. 7411 ................................................................................................. 30 CAA § 112, 42 U.S.C. § 7412 ........................................................................................ 30, 35 CAA § 301, 42 U.S.C. § 7601 .............................................................................................. 36 CAA § 302, 42 U.S.C. § 7602 ................................................................................5, 8, 24, 26 CAA § 304, 42 U.S.C. § 7604 ........................................................................... 31, 35, 36, 42 CAA § 307, 42 U.S.C. § 7607 .......................................................................................... 1, 11 Federal Regulations 40 C.F.R. § 50.12 .................................................................................................................... 3 40 C.F.R. § 51.112 ................................................................................................................ 16 40 C.F.R. § 51.15 .................................................................................................................. 16 40 C.F.R. § 51.211 ................................................................................................................ 16 40 C.F.R. § 51.214 ................................................................................................................ 16 40 C.F.R. § 51.321 ................................................................................................................ 16 40 C.F.R. § 58.16 .................................................................................................................. 16 40 C.F.R. § 70.6..................................................................................................................... 33 State Statutes and Regulations Ark. Code Reg. § 19.1004 .................................................................................................... 27 7 Del. Admin. Code 1103 .................................................................................................... 33 7 Del. Admin. Code 1104 .................................................................................................... 27 Fla. Admin. Code § 62-210.700 ..............................................................................20, 27, 37 vi USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 8 of 55 Ga. Comp. R. & Regs. 391-3-1-.02 .............................................................................. 25, 26 401 Ky. Admin. Reg. 50:055 ......................................................................................... 29, 33 La. Admin. Code tit. 33, pt. III, § 929 ............................................................................... 33 15A N.C. Admin. Code 2D0535 ........................................................................................ 32 Ohio Admin. Code 3745-15-06 .......................................................................................... 31 S.D. Admin. R. § 74:36:12:02 .............................................................................................. 22 Tenn. Comp. R. & Regs. § 1200-03-20-.07 ....................................................................... 32 Tenn. Comp. R. & Regs. § 1200-03-20-.02 ....................................................................... 22 Tenn. Comp. R. & Regs. § 1200-03-20-.09 ....................................................................... 32 W. Va. Code St. R. § 45-2-9.2 ............................................................................................. 27 W. Va. Code St. R. § 45-7-10.3 ........................................................................................... 28 Federal Register 47 Fed. Reg. 3,111 (Jan 2, 1982) ......................................................................................... 27 53 Fed. Reg. 34,500-01 (Sept. 7, 1988) .............................................................................. 15 54 Fed. Reg. 19,169-01 (May 4, 1989)................................................................................ 17 58 Fed. Reg. 41,430-01 (Aug. 4, 1993) ............................................................................... 15 71 Fed. Reg. 19,432-01 (Apr. 14, 2006) ............................................................................. 15 76 Fed. Reg. 41,424-01 (July 14, 2011) .............................................................................. 15 76 Fed. Reg. 763-01 (Jan. 6, 2011)...................................................................................... 15 78 Fed. Reg. 12,460 (Feb. 22, 2013), EPA-HQ-OAR-0322-0055............. 6, 8, 18, 20, 37 79 Fed. Reg. 55,920 (Sept. 17, 2014), EPA-HQ-OAR-2013-0322-0909 ....................... 18 80 Fed. Reg. 33,840 (June 12, 2015), EPA-HQ-OAR-2012-0322-1136. …..ii, ix, 1, 6, 8, 9, 14, 15, 17, 19, 20, 21, 23, 24, 25, 26, 28, 29, 32, 34, 38 vii USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 9 of 55 Miscellaneous 1982 Memo, EPA-HQ-OAR-2012-0322-0005 .............................................................. 6, 7 1983 Memo, EPA-HQ-OAR-2012-0322-0006 .................................................................. 7 1999 Memo, EPA-HQ-OAR-2012-0322-0007 ........................................................ 6, 7, 17 2001 Memo, EPA-HQ-OAR-2013-0322-0038 .................................................................. 8 Am. Heritage Dictionary of the English Language (1981)......................................................... 13 Ariz. Comment, EPA-HQ-OAR-2012-0322-0599 .......................................................... 17 Black’s Law Dictionary (9th ed. 2009) ................................................................................... 13 Colo. Comment, EPA-HQ-OAR-2012-0322-0525 ......................................................... 21 Del. Comment, EPA-HQ-OAR-2012-0322-0570 ........................................................... 16 Fla. Comment, EPA-HQ-OAR-2012-0322-0878 ............................................................ 17 Ga. Comment, EPA-HQ-OAR-2012-0322-0557 ............................................................ 16 N.C. Comment, EPA-HQ-OAR-2012-0322-0619 .......................................................... 32 Ohio Comment, EPA-HQ-OAR-2012-0322-0532.......................................................... 31 S.D. Comment, EPA-HQ-OAR-2012-0322-0441 ...............................................16, 17, 23 W. Va. Comment, EPA-HQ-OAR-2012-0322-0614 ....................................................... 29 viii USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 10 of 55 GLOSSARY 1982 Memo Mem. from Kathleen M. Bennett, Ass’t Adm’r for Air, Noise and Radiation to Reg’l Adm’rs, Regions I-X (Sept. 28, 1982) 1983 Memo Mem. from Kathleen M. Bennett, Ass’t Admr. For Air, Noise and Radiation to Reg’l Admrs., Regions I-X (Feb. 15, 1983) 1999 Memo Mem. from Steven A. Herman, Ass’t Adm’r for Enforcement & Compliance Assur. to Reg’l Adm’rs, Regions I-X (Aug. 11, 1999) 2001 Memo Mem. from Eric Shaeffer, Dir., Ofc. of Regulatory Enforcement, to John S. Seitz, Dir., Ofc. of Air Quality Planning & Standards, Ofc. of Air & Radiation (Dec. 5, 2001) CAA or Act Clean Air Act, 42 U.S.C. § 7401 et seq. Comment Response EPA, Response to Comments on February 2013 and September 2014 Proposals for Action, “State Implementation Plans: Response to Petition for Rulemaking, Restatement and Update of EPA’s SSM Policy Applicable to SIPs; Findings of Substantial Inadequacy, and SIP Calls to Amend Provisions Applying to Excess Emissions During Periods of Startup, Shutdown and Malfunction” (May 2015) EPA United States Environmental Protection Agency NAAQS National ambient air quality standards SIP State implementation plan SIP Calls State Implementation Plans: Response to Petition for Rulemaking; Restatement and Update of EPA’s SSM Policy Applicable to SIPs; Findings of Substantial Inadequacy; and SIP Calls to Amend Provisions Applying to Excess Emissions During Periods of Startup, Shutdown, and Malfunction; Final Rule, 80 Fed. Reg. 33,840 (June 12, 2015) SSM Startup, shutdown, and malfunction ix USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 11 of 55 JURISDICTIONAL STATEMENT State Petitioners1 seek review of a final rule promulgated by the U.S. Environmental Protection Agency (EPA) entitled “State Implementation Plans: Response to Petition for Rulemaking; Restatement and Update of EPA’s SSM Policy Applicable to SIPs; Findings of Substantial Inadequacy; and SIP Calls To Amend Provisions Applying to Excess Emissions During Periods of Startup, Shutdown, and Malfunction; Final Rule,” 80 Fed. Reg. 33,840 (June 12, 2015) (the SIP Calls), Joint Appendix (JA), __. Petitions for review were timely filed under section 307(b)(1) of the Clean Air Act (CAA or Act), which provides this Court jurisdiction to review final EPA actions. STATEMENT OF THE ISSUES 1. Whether EPA may satisfy CAA § 110(k)(5)’s requirement to “find[]” that SIPs are “substantially inadequate” and call States’ SIPs solely on the basis of an asserted mismatch between the SIPs and CAA legal requirements, without making factual findings supporting its determination that any inadequacies are substantial. 2. Whether, assuming EPA’s interpretation of its SIP call authority was permissible, EPA properly called SIPs because they contain what EPA terms 1 State of Florida, State of Alabama, State of Arizona, State of Arkansas, State of Delaware, State of Georgia, State of Kansas, State of Louisiana, State of Mississippi, State of Missouri, State of Ohio, State of Oklahoma, State of South Carolina, State of South Dakota, State of West Virginia, Commonwealth of Kentucky, North Carolina Department of Environment and Natural Resources, State of Texas, and State of Tennessee. 1 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 12 of 55 “automatic exemptions,” “director’s discretion provisions,” and “affirmative defenses” for emissions during SSM periods. 3. Whether, to the extent applicable, EPA may call SIPs for reasons that it did not find constitute substantial inadequacies. INTRODUCTION The Clean Air Act (the Act) establishes a system of cooperative federalism to reduce air pollution in the United States. In that system, EPA and the States occupy distinct and complementary roles. EPA creates National Ambient Air Quality Standards (NAAQS) setting the maximum ambient-air concentration for certain air pollutants that will not jeopardize public health or welfare. The States may provide input, but the decision lies with EPA. States are responsible for determining the best approach to achieve the NAAQS through state implementation plans (SIPs). If the SIP meets the requirements of the Act, EPA must approve the SIP. EPA has no authority to substitute its policy preferences about the best means to reduce air pollution. This system has been in place since Congress passed the Act in 1970. Once EPA approves a SIP, it cannot require a State to revise that SIP just because EPPA interprets some aspect of the SIP as technically inconsistent. Instead, section 110(k)(5) of the Act requires EPA to “find[] that [the SIP] is substantially inadequate.” Only upon making such a finding can the EPA require a State to revise the SIP. This procedure is called a SIP call. 2 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 13 of 55 This case involves EPA’s decision to call SIPs in 35 States and the District of Columbia (for provisions applicable in 45 statewide and local jurisdictions) because of how those SIPs treated periods of startup, shutdown, and malfunction (SSM). The SIP Calls do not purport to improve air quality. EPA made no findings at all about the air-quality effects of the States’ SSM regulations in general, much less Statespecific findings about the specific provisions that EPA has identified as substantially inadequate. Instead, EPA asserted that certain CAA requirements are “fundamental,” such that any SIP provision that failed to satisfy them was substantially inadequate. In the absence of any factual finding of substantial inadequacy, however, EPA’s SIP Calls do not comply with the Act. And even had it correctly construed its SIP call authority, EPA’s superficial analysis of SIP provisions classified SIPs as substantially inadequate when, under EPA’s own reading of the Act, they plainly are not. These failures require the SIP Call to be vacated. STATUTES AND REGULATIONS Pertinent statutes, regulations, and SIP provisions are set forth in the separately filed Statutory and Regulatory Addendum. STATEMENT OF THE CASE I. THE SIP PROGRAM OF THE CLEAN AIR ACT Under section 109 of the Act, EPA establishes primary and secondary NAAQS to protect human health and welfare. These air quality standards set maximum concentrations for the pollutants in the ambient air, e.g. 40 C.F.R. § 50.12 (1.5 µg/m3 3 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 14 of 55 for lead); they do not themselves set limitations on how much or how fast a source can emit a particular pollutant. In setting the NAAQS, EPA is to determine, based on available scientific information, the maximum concentration of the pollutant in the ambient air “requisite” to protect public health and welfare, CAA § 109(b)—that is, the standards must provide limits that are “sufficient, but not more than necessary,” with an adequate margin of safety to achieve those goals. Whitman v. Am. Trucking Ass’n, 531 U.S. 457, 473 (2001). EPA is not, however, primarily responsible for attaining the NAAQS. The Act is an exercise in cooperative federalism. EPA “identifies the end to be achieved” by establishing the NAAQS, and States “choose the particular means for realizing that end” through their SIPs. Virginia v. EPA, 108 F.3d 1397, 1408 (D.C. Cir. 1997) . Thus, States, not EPA, have the “primary responsibility for assuring air quality” through a “state implementation plan” (or SIP), through which a State “specif[ies] the manner in which national primary and secondary ambient air quality standards will be achieved and maintained.” CAA § 107(a). Section 110 of the Clean Air Act sets requirements for SIPs. Two provisions are particularly relevant here. First, a SIP must contain “enforceable emission limitations and other control measures, means, or techniques . . . as may be necessary or appropriate to meet the applicable requirements of this chapter.” CAA § 110(a)(2)(A). The Act provides States with broad discretion to regulate through “emission limitations” and “other control measures” that the State deems “necessary 4 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 15 of 55 or appropriate.” Id. That discretion is apparent in the definition of “emission limitation”: any “requirement” that “limits the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” Id. § 302(k). The definition includes “any requirement relating to the operation or maintenance of a source to assure continuous emission reduction, and any design, equipment, work practice or operational standard promulgated under this chapter.” Id. Separately, a SIP must contain a “program to provide for the enforcement” of various requirements, including emission limitations. CAA § 110(a)(2)(C). 2 Thus, the Act gives States discretion over how to design emission limitations and other control measures to attain the NAAQS and how those limitations should be enforced. If the SIP meets CAA requirements, EPA “shall approve” the plan. CAA § 110(k)(3). In other words, if the SIP meets CAA requirements, the Act gives EPA “no authority to question the wisdom of a State’s choices of emission limitations.” Train v. NRDC, 421 U.S. 60, 79 (1975); see also Virginia, 108 F.3d at 1410 (“Congress did not give EPA authority to choose the control measures or mix of measures states would put in their implementation plans.”). Once a SIP is approved, the Act also significantly limits EPA’s authority to require a State to change it. Under the SIP call authority at issue here, only if EPA “finds on the basis of information available to the 2 This obligation is independent of the obligation to ensure that the State has sufficient resources to carry out the SIP. Id. § 110(a)(2)(E). 5 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 16 of 55 Administrator” that the SIP is not just inadequate, but “substantially” so, must a State revise its SIP. CAA §§ 110(a)(2)(H)(ii), 110(k)(5). II. REGULATION OF SSM PERIODS Since States first submitted SIPs in the 1970s, they have recognized that emissions controls may not work as well when sources are starting up, shutting down, or malfunctioning. EPA, too, has “recognize[d]” both that “even the best available emissions control systems may not be consistently effective during startup and shutdown periods” and “even equipment that is properly designed and maintained can sometimes fail.” 1999 Memo 2, 3, JA __. Therefore, SIPs have “often included” special provisions for operation during SSM periods, relating both to what the limitations are during those periods, and also how enforcement should take place. 78 Fed. Reg. 12,460, 12,464 (Feb. 22, 2013), JA __. The widespread nature of such provisions is best illustrated by the fact that the SIP Calls require revisions to SSM rules in 35 States and the District of Columbia. 80 Fed. Reg. at 33,847. EPA first suggested its preferred approach to “excess emissions,” defined as any time an SSM period resulted in “an air emission rate which exceeds any applicable emission limitation,” in SIPs in 1982. 1982 Memo 3, JA __. Although EPA determined that excess emissions should be treated as violations, it recognized that in some cases, excess emissions would result from unavoidable malfunctions. Id. Rather than offer an “automatic exemption where a malfunction is alleged by a source,” EPA advised States to use enforcement discretion. Id. Under EPA’s preferred approach, the 6 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 17 of 55 State could “require the source to demonstrate to the appropriate State agency that the excess emissions, though constituting a violation, were due to an unavoidable malfunction.” Id. For periods of startup and shutdown, EPA believed no enforcement discretion was appropriate, because sources should be able to plan for such events. Id. at 4, JA __. The next year, EPA reversed course on start-up and shut-down periods, recognizing that sometimes “careful and prudent planning and design will not totally eliminate infrequent[,] short periods of excesses during startup and shutdown.” 1983 Memo 1-2, JA __. Although the 1982 and 1983 Memos both addressed States’ treatment of emissions that exceeded applicable limitations, EPA did not purport to limit States’ authority to determine that certain emission limitations would not apply during SSM periods. In 1999, EPA again revised its SSM policy to reduce the possibility that SSM emissions could cause sources with unavoidable SSM emissions to be subject to monetary penalties.3 For both malfunctions and startup and shutdown, EPA advised States that they could create affirmative defenses to monetary penalties subject to certain criteria 1999 Memo Attachment 3-5, JA __. These defenses, if satisfied, would allow sources to avoid monetary penalties in citizen suits, but they would be subject to injunctions for violating the applicable emissions standard. EPA later clarified that the 3 This issue arose following the 1990 CAA amendments, which allowed citizen suits to seek monetary penalties for the first time. See NRDC v. EPA, 749 F.3d 1055, 1062 (D.C. Cir. 2014). 7 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 18 of 55 1999 Memo applied only to future SIP revisions and “was not intended to affect existing permit terms or conditions.” 2001 Memo 2, JA __. III. THE SIP CALL The SIP Calls arise out of a 2011 EPA settlement with Sierra Club. Under the consent decree, EPA was required to respond to the organization’s petition concerning SIP provisions addressing SSM periods. The petition asked EPA to call SIPs from 38 States and the District of Columbia because, among other reasons, they automatically exempted emissions during SSM periods, they gave the director of the State air pollution control agency discretion to provide exemptions from applicable emission limitations, or they provided affirmative defenses to an alleged violation. 78 Fed. Reg. 12,460, 12,464 (Feb. 22, 2013), JA __. EPA agreed with Sierra Club that automatic exemptions from emission limitations during SSM periods violate the requirement that a SIP contain continuous emission limitations under sections 110(a)(2)(A) and 302(k) of the Act, that director’s discretion provisions violate the prohibition on modifying SIPs without EPA approval, and reversing its previous position,4 that affirmative defenses improperly infringe on the courts’ jurisdiction to impose monetary penalties for violations in citizen suits. 80 Fed. Reg. at 33-889-924, JA __. EPA concluded that each type of provision failed “fundamental legal 4 EPA initially proposed to deny the Petition as to affirmative defenses to monetary penalties. 78 Fed. Reg. at 12,469. EPA reversed course after this Court disapproved such an affirmative defense in an EPA-created technology-based emission standard for certain hazardous air pollutants in NRDC v. EPA, 749 F.3d 1055 (D.C. Cir. 2014). See infra p. 35. 8 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 19 of 55 requirements” of the Act, rendering a SIP “substantially inadequate,” as required for a SIP call. In the SIP Calls, EPA required States to revise SIPs that, in its judgment, might be construed as containing automatic exemptions, directors’ discretion provisions, or affirmative defenses, and also identified other issues as to which EPA had not made a substantial-inadequacy finding. 5 Altogether, EPA called SIPs in 35 States and the District of Columbia (with provisions applicable in 45 statewide and local jurisdictions). 80 Fed. Reg. at 33,846, JA __. Nineteen State Petitioners, along with other petitioners, timely sought review. SUMMARY OF THE ARGUMENT In the SIP Call, EPA did not set out to address threats to air quality. The only basis EPA identified for the calls was the SIPs’ alleged failure to meet certain legal requirements of the CAA as EPA now interprets it. But the SIP call process is not designed to address any and all perceived shortcomings. Contrary to the plain language of CAA § 110(k)(5), EPA has made no “find[ings]” that support its conclusion that these claimed inadequacies are “substantial.” This problem is exemplified by EPA’s decision to call SIPs containing affirmative defenses to monetary penalties, which went from EPA’s preferred approach to addressing SSM emissions to a substantial inadequacy requiring a SIP call—not because EPA’s assessment of the effects of those provisions changed, but because its view of the law 5 EPA also revised its SSM policy, though it did not determine that aspects of the policy other than those just discussed constituted substantial inadequacies. See 80 Fed. Reg. at 33,927-29, 33,976-82, JA __. 9 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 20 of 55 did. Still more troubling, EPA interprets its SIP call authority to extend not just to such alleged technical inadequacies, but to potential ones. By reading the requirement to find a substantial inadequacy out of the Act, EPA significantly undermines Congress’s cooperative federalism design. Setting aside EPA’s disregard of section 110(k)(5)’s plain text, EPA’s decision to call various SIPs based on its conclusion that they contain improper automatic exemptions, director’s discretion provisions, and affirmative defenses rests on a combination of impermissible interpretations of both the Act and SIP provisions. These errors fall into four categories. First, EPA refused to consider simultaneously operating general-duty requirements that limit emissions during SSM periods just because they were not cross-referenced in the SSM provisions EPA deemed inadequate. Second, EPA incorrectly applied its definition of emission limitation to determine that certain SSM provisions did not limit emissions, even though, on their face, those provisions require sources to limit emissions at all times, including SSM periods, to avoid a violation. Third, among other errors, EPA incorrectly interpreted provisions that guide State air agencies’ exercise of their enforcement discretion to preclude EPA and citizen enforcement, notwithstanding those States’ comments pointing out the incorrect interpretation. Fourth, EPA erred by asserting that the Act does not permit affirmative defenses, either to violations or just to monetary penalties. In doing so, it impermissibly relied on this Court’s decision in NRDC v. EPA, 749 F.3d 1055 (D.C. Cir. 2014), to conclude that the Act prevents States from including 10 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 21 of 55 affirmative defenses to monetary penalties in their SIPs, notwithstanding that the Act specifically gives States the authority to design an enforcement regime for their SIPs, that NRDC explicitly does not address affirmative defenses in SIPs, and that the Fifth Circuit previously specifically approved the affirmative defenses that EPA now claims are impermissible. Finally, it is unclear whether EPA also purports to call SIPs based on factors beyond those issues that it has determined to constitute substantial inadequacies. To the extent those issues are the basis for the SIP Call, EPA’s action is improper. For these reasons, the SIP Call should be vacated. STANDING State Petitioners have standing as States or State agencies required to revise SIPs to comply with EPA’s SIP Call. West Virginia v. EPA, 362 F.3d 861, 868 (D.C. Cir. 2004). STANDARD OF REVIEW Final agency actions under the Clean Air Act must be vacated when “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” CAA § 307(d)(9)(A); Sierra Club v. EPA, 551 F.3d 1019, 1027 (D.C. Cir. 2008). When considering EPA’s action under the CAA, courts must first determine de novo whether “the intent of Congress is clear” by “employing traditional tools of statutory construction.” Nat’l Ass’n of Clean Air Agencies v. EPA, 489 F.3d 1221, 1228 (D.C. Cir. 2007). If so, EPA is accorded no deference, because “the court, as well as the agency 11 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 22 of 55 must give effect to the unambiguously expressed intent of Congress.” Id. Only when the statute does not resolve an issue will the Court defer to EPA, provided that the agency’s interpretation is reasonable. Id. ARGUMENT I. EPA HAS NOT PROPERLY FOUND INADEQUATE. THAT ANY SIP IS SUBSTANTIALLY EPA’s most fundamental error was failing to comply with the Act’s requirement to “find[]” that a SIP is “substantially inadequate to attain or maintain the relevant national ambient air quality standard . . . or to otherwise comply with any requirement of” the Act before calling a SIP. CAA § 110(k)(5). Specifically, EPA erred by determining that the standard is satisfied whenever EPA interprets any SIP provision as not complying with a legal requirement, regardless of the effects or magnitude of the inadequacy. Congress’s requirement of a “find[ing] on the basis of information available to the administrator,” id. § 110(a)(2)(H)(ii), contemplates that a SIP call will be based on facts, not speculation. Beyond that, EPA extends its authority to call SIPs to provisions that may not even be “inadequate . . . to comply” with CAA requirements, determining that ambiguous provisions, or even provisions it misread, can justify a SIP call. EPA’s misinterpretation of its SIP call authority alone requires vacatur and remand for EPA to apply the correct legal standard. Cty. of L.A. v. Shalala, 192 F.3d 1005, 1011 (D.C. Cir. 1999). 12 USCA Case #15-1166 1. Document #1604344 Filed: 03/16/2016 Page 23 of 55 EPA’s first error was to ignore the required factual finding of substantial inadequacy. To be subject to a call, a SIP must not only be “inadequate” to meet the NAAQS or comply with a CAA requirement; it must be “substantially” so—that is, “[c]onsiderable in importance, value, degree, amount, or extent.” Am. Heritage Dictionary of the English Language 1284 (1981). Although Congress did not precisely define the point at which an inadequacy becomes substantial, it did tell EPA that the substantial-inadequacy determination must result from a “find[ing] on the basis of information available to the Administrator.” CAA § 110(a)(2)(H)(ii); see also id. § 110(k)(5). By requiring that EPA find substantial inadequacy, Congress directed EPA to review evidence and make a factual determination to justify its SIP call. Black’s Law Dictionary 707 (9th ed. 2009) (defining “find” as “[t]o determine a fact in dispute by verdict or decision”); cf. Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43-44 (1983) (administrative finding needed to be based on “substantial evidence”); Appalachian Power Co. v. EPA, 251 F.3d 1026, 1034 (D.C. Cir. 2001) (“failure to examine the relevant data” rendered EPA rulemaking arbitrary). Moreover, Congress gave EPA the tools to require “[a]ny State” to submit “any . . . information” that EPA requires to assess the “need for revision” of any SIP. CAA § 110(p). Comparing the SIP call standard to other standards of review in section 110 reinforces this interpretation. When a SIP is submitted for approval in the first instance, EPA must approve it only “if it meets all of the applicable requirements” of 13 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 24 of 55 the CAA. Id. § 110(k)(3). Similarly, when a State submits a new SIP revision, EPA must disapprove it if it “would interfere with any applicable requirement” of the CAA. Id. § 110(l). By their plain text, these are not substantial-compliance standards. They are absolute-compliance standards; EPA must approve a SIP or SIP revision only if it meets all applicable CAA requirements. Thus, although a SIP may be inadequate based solely on a mismatch between a legal requirement of the Act and the text of the SIP—and therefore not approvable in the first instance under sections 110(k)(3) or 110(l)—determining whether it is substantially so involves a factual question, not just a legal one. Rather than respecting the differences between these standards, EPA collapses them, contending that it may call SIPs “whenever the Agency later determines [revision] to be necessary to meet CAA requirements.” 80 Fed. Reg. at 33,937. In so doing, EPA alters the cooperative federalism balance that Congress designed. Instead of the factual inquiry the Act demands, EPA created a category of “fundamental legal requirements” that must be satisfied absolutely to avoid a SIP call. EPA does not explain what separates fundamental requirements that create substantial inadequacies from those non-fundamental ones that do not. Congress found all of the Act’s requirements important enough to put in the Act and required EPA to ensure that all new plans and revisions satisfy them all. CAA §§ 110(k)(3), 110(l). More significantly, EPA’s argument that some requirements are fundamental implicitly concedes that facts about the practical effects of an inadequacy are the only 14 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 25 of 55 way to determine if that inadequacy is substantial. EPA justifies this new category based heavily on factual scenarios that could result if these “fundamental legal requirements” are not met. But rather than find those facts, as required, EPA speculated about what those facts might be. It hypothesized that the target SIP provisions would undermine “attainment and maintenance of the NAAQS, protection of PSD increments[,] and improvement of visibility,” 80 Fed. Reg. at 33,927, 33,929, JA __, or allow “potentially dramatic adverse impacts inconsistent with the objectives of the CAA,” 80 Fed. Reg. 33928, JA __. Notably, EPA did not cite a single instance in which any State’s SSM provisions prevented attainment of the NAAQS, PSD increments, or improved visibility, or caused any other “potentially dramatic” adverse impacts in the SIP Calls. Nor did it cite any predictive studies or models demonstrating that its conclusion rested on anything other than conjecture. This is significant, because SSM rules, by their nature, apply to very limited periods of operation, leading one to expect their impact would be minimal. EPA, of course, knows how to compile a factual record supporting its administrative actions, and it has done so in previous SIP calls. 6 Because EPA’s determination rests only on speculation, it cannot constitute a finding. See Virginia, See, e.g., 76 Fed. Reg. 41424-01 (July 14, 2011) (SIP call in light of NAAQS exceedances); 76 Fed. Reg. 763-01 (Jan. 6, 2011) (proposed SIP call based on modeling); 71 Fed. Reg. 19432-01 (Apr. 14, 2006) (SIP call in light of NAAQS exceedances); 58 Fed. Reg. 41430-01 (Aug. 4, 1993) (SIP call based on predictive modeling anticipating NAAQS exceedances); 53 Fed. Reg. 34500-01 (Sept. 7, 1988) (SIP call in light of NAAQS exceedances). 15 6 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 26 of 55 108 F.3d at 1415 (noting that a finding of substantial inadequacy could not be made “[i]n the absence of applicable modeling,” and vacating a SIP call on that basis). As important as the facts that EPA did not find is the “information available” that EPA simply ignored. See § 110(a)(2)(H)(ii). EPA requires States to submit ambient air quality data to EPA quarterly, pursuant to monitoring plans it approves. CAA § 110(a)(2)(B); 40 C.F.R. §§ 51.15, 58.16. In addition, SIPs require stationary sources to continuously monitor emissions, with annual reports to EPA. 40 C.F.R. §§ 51.15, 51.211, 51.214, 51.321. Further, States must demonstrate that submitted SIPs will result in attainment of the NAAQS, which includes consideration of actual source emissions, applicable emission limitations, and any applicable exemptions or alternative limitations. Id. §§ 51.15, 51.112. Had EPA considered this information, it is hard to imagine that EPA would have found States’ SSM provisions substantially inadequate across the board, or even State by State. For example, Georgia reported to EPA that in 2012, two-thirds of Georgia sources had no emissions exceeding numerical standards, and the average duration of excess emissions during SSM Periods for those that did was just six hours per reporting period. Ga. Comment 2, JA __. South Dakota indicated it fully attains all NAAQS. S.D. Comment 3, JA __. Delaware pointed out that its provision allowing the State to set specific rules for startup and shutdown periods has not caused excess emissions that contribute to its ozone nonattainment problem. Del. Comment 3, JA __. Similarly, Arizona’s affirmative defense provision, which applies only if the emissions do not cause a 16 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 27 of 55 NAAQS violation and good design and maintenance procedures are followed, had never been invoked since it was created in 2001. Ariz. Comment 1-2, JA __. EPA’s failure to point to any facts concerning adverse effects of the States’ SSM provisions is particularly striking in light of the long and widespread experience with the SSM rules EPA has called. Many SIP provisions EPA now considers substantially inadequate have existed for decades. E.g., Fla. Comment 4, JA __ (Florida’s SSM provision first approved in 1982); S.D. Comment 3, JA __ (South Dakota’s provision first approved in 1975); 54 Fed. Reg. 19,169-01 (May 4, 1989) (approving Kentucky’s provision in 1989). If, in fact, any of the dozens of SIPs EPA called were substantially inadequate, one would expect that EPA could marshal some evidence as to the provisions’ real-world detrimental effects. Instead, EPA did the opposite, acknowledging that States may permissibly respond to the SIP Call by loosening emission limitations on sources to ensure that increased emissions during SSM periods do not result in violations, paradoxically allowing for more air pollution, not less. 80 Fed. Reg. at 33,955, JA __. EPA’s reversal on affirmative defenses perfectly illustrates the irrelevance of factual findings to the SIP Call. In its 1999 Memo, EPA recommended that States address SSM events by giving affirmative defenses to monetary penalties when sources could show that it was impossible to avoid excess emissions and satisfy other conditions. 1999 Memo Attachment 3-6, JA __. The February 2013 NPRM continued to authorize “appropriately drawn” affirmative defenses, albeit with several new 17 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 28 of 55 restrictions, 78 Fed. Reg. 12,469-70, 12,478-79, JA __, and one month later, the Fifth Circuit approved EPA’s longstanding view, holding that the CAA authorizes States to include affirmative defenses. See Luminant Generation Co. v. EPA, 714 F.3d 841 (5th Cir. 2013); accord 79 Fed. Reg. 55,920, 55,945 (Sept. 17, 2014), JA __. EPA abruptly shifted course in its September 2014 supplemental notice, concluding that all affirmative defenses constitute substantial inadequacies. 79 Fed. Reg. at 55,929-30, JA __. What changed during this one-and-a-half-year period? Nothing, except this Court’s decision in NRDC v. EPA, 749 F.3d 1055 (D.C. Cir. 2014), that EPA was not authorized to create affirmative defenses in its hazardous air pollutant standards. 79 Fed. Reg. at 55,929-30, 55,935, 55,945, JA __. But NRDC did not address state authority to include affirmative defenses to monetary penalties in SIPs under CAA § 110. See infra pp. 35-37. Regardless, EPA has identified no facts that would support “find[ing]” such an inadequacy “substantial,” contrary to EPA’s prior conclusion that Texas’s SIP was appropriately drawn to balance air-quality protection with the reality of SSM periods. Just as before, Texas’s affirmative defense applies only during unplanned and unavoidable “upset” periods, provided that such emissions do not “cause or contribute to an exceedance of the NAAQS, PSD increments, or a condition of air pollution.” Luminant, 714 F.3d at 854 (quoting Tex. Admin. Code § 101.222(c)(9)).7 Luminant and Texas’s affirmative defense provision are discussed in greater detail in the Texas Petitioner’s brief. 18 7 USCA Case #15-1166 2. Document #1604344 Filed: 03/16/2016 Page 29 of 55 EPA’s interpretation of its SIP call authority does not stop at actual but trivial inadequacy to meet CAA legal requirements. EPA claims authority to issue a SIP call based on the mere potential for an inadequacy—in other words, EPA believes it may issue SIP calls “to address ambiguous SIP provisions that could be read by a court in a way that would violate the requirements of the CAA.” 80 Fed. Reg. at 33,926, JA __ (emphasis added). If a SIP might or might not contain a provision that is inadequate to comply with the CAA, then EPA has not shown that the SIP is inadequate, much less substantially so. But see US Magnesium, LLC v. EPA, 690 F.3d 1157, 1167-68 (10th Cir. 2012) (allowing EPA to call Utah’s SIP in light of “potential conflicts” between the SIP and CAA requirements). Still more ambitiously, EPA suggests that the fact that it overlooked applicable limitations during its review of the called SIPs justifies a call. Faced with arguments that it failed to take into account provisions that applied simultaneously with SIP-specific provisions, EPA responded, “If the EPA was unable to ascertain, what, if anything, applied,” then “regulated entities, members of and [sic] the public, and the courts will have the same problem.” 80 Fed. Reg. at 33,943, JA __. By transforming a standard that would protect any SIP that was not “substantially inadequate” into one that does not require even a genuine inconsistency with the Act, EPA makes the SIP call standard even lower than the standard for its initial review under section 110(k)(3). The CAA’s text makes it clear that Congress did not intend such a result. 19 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 30 of 55 EPA’s interpretation of its SIP call authority to force States to rewrite their SIPs on such a thin basis is particularly puzzling in light of its rejection of Sierra Club’s request that EPA not rely on State interpretive letters in the rulemaking process to clarify ambiguous provisions. 80 Fed. Reg. at 33,885, JA __. EPA recognized that “reliance on interpretive letters to address concerns about perceived ambiguity can often be the most efficient and timely way to resolve concerns about the correct meaning of regulatory provisions.” 80 Fed. Reg. at 33,885, JA __; see also Fla. Power & Light Co. v. Costle, 650 F.2d 579, 588 (5th Cir. 1981) (EPA “should defer to the state’s interpretation of the terms of its air pollution control plan when said interpretation is consistent with the Clean Air Act”). The alternative, as EPA recognizes, is to require States to “reinitiate a complete administrative process merely to resolve perceived ambiguity in a provision in a SIP submission.” 80 Fed. Reg. at 33,885. Relying on interpretive letters is particularly important in the SIP context, because the Act does not “specify that air agencies must use specific regulatory terminology, phraseology, or format” in SIP provisions. Id. But in pronouncing SIP provisions substantially inadequate, EPA rejected States’ explanations of state law and how their SIPs worked, often focusing on word choice. See, e.g., 78 Fed. Reg. at 12,503 (asserting that Fla. Admin. Code § 62-210.700(1) is an exemption, not a limitation, and focusing on the phrase “shall be permitted”). EPA’s decision to call SIPs in the face of States’ reasonable resolution of any EPA-perceived ambiguities is not the 20 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 31 of 55 cooperation that Congress envisioned. By extending its SIP call authority to reach provisions that it views as ambiguous or difficult to read, EPA substitutes its desire that States rewrite provisions that are at most potentially inadequate for Congress’s clear instruction that a SIP call requires not just actual, but substantial inadequacy. 3. In requiring EPA to meet a higher standard before calling a SIP, Congress protected States from the administrative burdens of rewriting SIPs every time EPA decides that a SIP could be written better. As EPA acknowledges, developing a SIP involves “time and resource-intensive administrative processes.” 80 Fed. Reg. at 33,885, JA __. In addition to months-long State rulemaking procedures, States must also determine just how, as a policy and technical matter, to comply with EPA’s new interpretation. This is no small matter. SSM events are not all created equal. Different sources face different challenges, and it may be difficult to develop the kinds of narrowly tailored SSM provisions that EPA apparently envisions, particularly in a cost-effective manner. See generally Colo. Comment 5-6, JA __. By forcing States to revise SIPs based on new interpretations of the Act without any finding that noncompliance has substantial effects, EPA undermines the balance of power Congress set in the Act. Because EPA called SIPs without “find[ing]” any SIP to be “substantially inadequate,” the SIP Calls must be vacated and remanded in their entirety. 21 USCA Case #15-1166 II. Document #1604344 Filed: 03/16/2016 Page 32 of 55 EVEN IF EPA PROPERLY INTERPRETED ITS SIP CALL AUTHORITY, IT MISINTERPRETED THE ACT’S REQUIREMENTS AND SIPS. EPA’s SIP Calls are unlawful even under its expansive view of its SIP call authority. In calling SIPs for containing so-called automatic exemptions, director’s discretion provisions, and affirmative defense provisions, EPA incorrectly interpreted both the Act and the SIPs. These errors require vacatur. A. EPA’s Decision to Ignore “General Duty” Requirements Violates the Act. First, EPA erred by refusing to consider what it calls “general duty” provisions that operate simultaneously with the SSM provisions EPA claims are substantially inadequate. These provisions require sources to control emissions through workpractice standards. For example, Tennessee’s SIP requires sources to “take all reasonable measures to keep emissions to a minimum” even during SSM periods. Tenn. Comp. R. & Regs. § 1200-3-20-.02(1). Moreover, emissions failures constitute violations if they exceed otherwise-applicable limits and result from “poor maintenance, careless operation or any other preventable upset condition or preventable equipment breakdown.” Id.8 General-duty provisions like Tennessee’s are 8 Similarly, while South Dakota’s SIP excepts from its visible emissions (“opacity”) restrictions for brief periods of SSM and soot blowing, and malfunctions. S.D. Admin. R. § 74:36:12:02(3), other rules in the SIP require sources to be in compliance with all criteria pollutant emission limitations or restrictions at all times, except where federal regulations provide exceptions. In its 40-plus year existence, South Dakota’s visible emission exception has not interfered with meeting or 22 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 33 of 55 plainly “requirement[s] relating to the operation or maintenance of a source” that, in conjunction with other provisions of the SIP, continuously limit emissions, albeit “without necessarily applying a single standard.” Sierra Club, 551 F.3d at 1027. EPA claims that general-duty provisions cannot be considered part of an emission limitation because they “are often located in different parts of the SIP and often not cross-referenced or otherwise identified as part of the putative continuously applicable emission limitation.” 80 Fed. Reg. at 33,903, JA __. But EPA identifies no statutory basis for requiring Tennessee or any other State to cross-reference all applicable requirements that form a continuous emission limitation or collect them in any other manner EPA prefers. On the contrary, it acknowledges elsewhere that the Act specifies no “specific regulatory terminology, phraseology, or format.” 80 Fed. Reg. at 33, 885, JA __. Because EPA can point to nothing in the Act that requires States to include all facets of a limitation in the same “part” of the SIP, or to crossreference all applicable provisions, its cannot dictate to States that their SIPs be worded or structured in a particular manner. See Texas v. EPA, 690 F.3d 670, 679 (5th Cir. 2012) (noting that a “state’s ‘broad responsibility regarding the means’ to achieve better air quality” includes the ability to choose “its own sentence structure”). Nothing in the Act permits EPA to ignore general-duty provisions. maintaining compliance with the NAAQS., and the State is in attainment for all of the NAAQS. See S.D. Comment, JA __. 23 USCA Case #15-1166 B. Document #1604344 Filed: 03/16/2016 Page 34 of 55 EPA Incorrectly Interpreted SIPs As Containing Automatic Exemptions During SSM Periods. The first category EPA faults is so-called “automatic exemptions” from otherwise-applicable requirements. 9 Assuming that merely containing a provision that provides a limited automatic exemption renders a SIP “substantially inadequate,” but see supra pp. 12-22, EPA errs both in its interpretation of the CAA and its reading of the SIPs. In rejecting comments that the provisions are “enforceable emission limitations” under CAA § 110(a)(2)(A), EPA has ignored that the provisions set enforceable requirements, which is all the Act requires. Under the CAA, an emission limitation is any “requirement” that “limits the quantity, rate, or concentration of emissions . . . on a continuous basis.” CAA § 302(k). The requirement need not be numerical; it includes any “requirement relating to the operation or maintenance of a source” and “any design, equipment, work practice or operational standard.” Id. This “broad phrase” means that an emission limitation can “‘assure continuous emission reduction’ without necessarily continuously applying a single standard.” Sierra Club, 551 F.3d at 1027 (quoting CAA Eleven State Petitioners’ SIPs were called on this basis. See 80 Fed. Reg. at 33,960 (Delaware), 33,961-62 (West Virginia), 33,962 (Florida), 33,962-63 (Georgia), 33,964 (North Carolina and South Carolina), 33,966-67 (Ohio), 33,967 (Arkansas), 33,967-68 (Louisiana), 33,969 (Kansas), 33,971 (South Dakota). Delaware’s SIP was not called for malfunction provisions, and Delaware does not join arguments concerning malfunction periods. 24 9 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 35 of 55 § 302(k)). 10 All Congress sought to do in requiring continuity was “exclude intermittent control technologies from the definition of emission limitations.” Id. EPA claims to share this understanding. In the SIP Calls, it “wishe[d] to be very clear” that emission limitations “may be composed of a combination of numerical limitations, specific technological control requirements and/or work practice requirements.” 80 Fed. Reg. at 33,889, JA __. Specifically, EPA contemplates that SIPs “may include alternative emission limitations” for SSM periods, substituting for “otherwise applicable emission limitations.” Id. at 33,913, JA __. Moreover, EPA recognizes that States have “considerable discretion in how they elect to structure or word their state regulations” to provide enforceable emission limitations. Id. at 33,886. In the SIP Calls, however, EPA failed to apply this understanding, and instead called SIPs based on formal requirements for SIP drafting invented out of whole cloth. Georgia’s SIP well illustrates the problems with EPA’s approach. EPA claims that Ga. Comp. R. & Regs. 391-3-1-.02(2)(a)7 provides an automatic exemption during SSM periods. 80 Fed. Reg. at 33,963, JA __. EPA ignores that Rule 391-31.02(2)(a)7 itself requires sources to use “best operational practices to minimize emissions,” and “minimize[]” the duration of excess emissions to avoid a violation, and it specifically does not allow excess emissions due to “poor maintenance, poor operation, or any other equipment or process failure which may reasonably be 10 As the Industry Petitioners’ brief explains, EPA has incorrectly interpreted the emissions limitation requirement of continuity. As explained here, even if EPA’s interpretation were correct, it has incorrectly applied it to SIPs. 25 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 36 of 55 prevented.” Ga. Comp. R. & Regs. 391-3-1-.02(2)(a)7. The provision is an “emission limitation” because it is a “requirement relating to the operation . . . of a source” that “assure[s] continuous emission reduction,” CAA § 302(k)—i.e., a requirement to use “best operational practices to minimize emissions,” even during SSM periods.11 EPA focuses on form, not substance. It faults provisions like Georgia’s for not being independently enforceable. According to EPA, if the duties in Rule 391-31.02(2)(a)7 “were independent parts of an emission limitation (rather than merely preconditions for an exemption), then one would expect that periods of time could exist when the source was liable for violating those general duties rather than the default emission limitation.” See 80 Fed. Reg. at 33,904, JA __. In other words, the problem appears to be that when EPA or someone else seeks to assert a violation, the plaintiff will claim the default limitation has been violated, not Rule 391-3-1.02(2)(a)7. What EPA does not assert is that Georgia has no “requirement” that “assures continuous emission reduction” during SSM periods. See CAA § 302(k). Although Rule 391-3-1.02(2)(a)7 provides that “excess emissions shall be allowed” if the provision’s conditions are met, failing to meet those conditions means the source is subject to penalties for violating the otherwise-applicable limitation. As with EPA’s 11 Moreover, like many other SIPs, Georgia’s SIP imposes duties to avoid causing NAAQS violations, Ga. Comp. R. & Regs. § 391-3-1.02(4)(a); not to construct or operate a source in a manner that violates permit restrictions, PSD requirements or applicable increments, id. § 391-3-1.02(1)(c); and to report certain emissions due to malfunctions or breakdowns at major sources, facilitating enforcement id. § 391-3-1.02(6)(b)(1)(iv); see also supra pp. 22-23 (explaining why EPA’s failure to consider general duties requires remand). 26 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 37 of 55 rejection of general duty provisions, EPA’s inadequacy determination for so-called “automatic exemptions” improperly rests on word choice, not the substance of what the SIPs require. EPA’s treatment of Georgia is not unique. Florida similarly requires “best operational practices to minimize emissions [to be] adhered to” during SSM periods, requires that such periods constitute no more than two hours of any twenty-four hour period, and prohibits emissions resulting from “poor maintenance, poor operation, or any other equipment or process failure which may reasonably be prevented.” Fla. Admin Code § 62-210.700.12 Similarly, Delaware sources are not in violation when “emissions from [a source] during start-up and shutdown are governed by an operation permit,”e.g., 7 Del. Admin. Code 1104, § 1.5. Arkansas provides an alternative limitation when increased emissions result from a “sudden and unavoidable breakdown, malfunction or upset of process or emission control equipment, or sudden and unavoidable upset of operation,” provided that the increase is “not the result of negligence.” Ark. Code Reg. § 19.1004(H). West Virginia requires that sources “[a]t all times, including periods of start-ups, shutdowns and malfunctions,” be operated “in a manner consistent with good air pollution control practice for minimizing emissions,” W. Va. Code St. R. § 45-2-9.2, and the same 12 As EPA itself recognized when it approved Florida’s SSM provision, “[i]n effect, the upset and startup rule revision recognizes the occurrence of unavoidable malfunctions and provides a definite control rule to deal with them.” 47 Fed. Reg. 3,111, 3,111 (Jan 2, 1982). 27 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 38 of 55 standard applies to maintenance periods, id. § 45-7-10.3. EPA repeatedly ignores these limitations with no statutory basis. Because EPA’s decision to call SIPs for containing automatic exemptions lacks any basis in the Act’s legal requirements, vacatur is required. C. EPA Incorrectly Determined That Director’s Discretion Provisions Violate the Act. In the SIP Call, EPA directed many States to revise what it terms “director’s discretion provisions.”13 The U.S. Court of Appeals for the Fifth Circuit has held that director’s discretion provisions comply with the CAA. See Texas v. EPA, 690 F.3d 670, 682-84 (5th Cir. 2012); Luminant Generation Co. v. EPA, 675 F.3d 917, 930-32 (5th Cir. 2012). Because EPA has yet again failed to show that such provisions are inconsistent with the CAA, this Court should do so as well. EPA’s analysis of these provisions contains three kinds of error. First, EPA mischaracterized provisions as giving States’ air pollution control agency directors “unbounded” discretion to grant “complete exemptions” from all SIP emission limitations. 80 Fed. Reg. 33,917, JA __. In reality, these provisions allow exemptions from numerical emission limitations only if the source has complied with alternative emission standards. In other words, as with its automatic exemption Eleven State Petitioners’ SIPs were called on this basis. See 80 Fed. Reg. at 33,960 (Delaware), 33,961-62 (West Virginia), 33,962 (Alabama), 33,963 (Kentucky), 33,964 (North Carolina), 33,965 (Tennessee), 33,966-67 (Ohio), 33,967-68 (Louisiana), 33,968 (Oklahoma), 33,969 (Kansas and Missouri), JA __. 13 28 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 39 of 55 determinations, supra pp. 25-26, EPA has failed to recognize that these exemptions themselves contain non-numerical limitations. Kentucky’s SIP illustrates the problem. Kentucky’s SIP provides that “[e]missions which, due to shutdown or malfunctions, temporarily exceed” otherwise applicable emission standards “shall be deemed in violation of such standards unless” the source shows—and the State enforcement agency’s director determines—that the source has complied with several workpractice and operational standards. 401 Ky. Admin. Reg. 50:055 § 1(1). Among other things, the source must establish that “[a]ll reasonable steps were taken to correct, as expeditiously as practicable, the conditions causing the emissions to exceed the standards, including the use of off-shift labor and overtime if necessary,” “all reasonable steps were taken to minimize the emissions and their effect on air quality resulting from the occurrence,” and the SSM event “was not caused entirely or in part by poor maintenance, careless operation or any other preventable upset conditions or equipment breakdown.” Id. § 1(4). See also, e.g., W. Va. Comment 11-12 (explaining a similar error with respect to West Virginia’s SIP). Second, EPA also argued that director’s discretion provisions empower State enforcement agencies to unilaterally revise their SIPs without undergoing the procedure that the CAA requires for SIP revisions. See 80 Fed. Reg. at 33,918-19. Like its continuity objection, this argument rests on a misunderstanding of the SIPs. It is true that states generally may not suspend or otherwise modify SIP requirements with respect to any stationary source, see CAA § 110(i), and they may revise their SIPs only 29 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 40 of 55 through the procedure established in the CAA, see id. § 110(l). But the director’s exercise of discretion according to established criteria does not revise a SIP or suspend or otherwise modify a SIP’s provisions—it merely applies them. EPA’s assertion to the contrary defies common sense. Under EPA’s reasoning, EPA “revises” the CAA whenever it exercises discretion that the Act confers to choose between a default and alternative manner of regulating emissions. For example, the CAA tasks EPA with the development of “standards of performance” for new stationary sources, as well as “emission standards” for control of hazardous air pollutants. CAA §§ 111(b)(1)(B), 112(d)(1). However, “if in the judgment of the Administrator, it is not feasible to prescribe or enforce a standard of performance” or an emission standard, a “design, equipment, work practice, or operational standard” may be appropriate. Id. § 111(h)(1); see also id. § 112(h)(1).14 EPA surely would not contend that its exercise of discretion to promulgate alternative standards according to criteria outlined in the CAA is an amendment of the CAA, rather than just an application of it. Why, then, should a state director’s exercise of discretion to apply an alternative standard according to criteria established in a SIP be treated differently? This Court should reject EPA’s unfounded characterization of director’s discretion provisions. 14 The CAA also gives EPA discretion to exempt sources from certain CAA requirements altogether. See, e.g., CAA § 361a(a) (exemption of source categories from permitting requirements). 30 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 41 of 55 Third, EPA offered enforcement-related objections. Specifically, EPA asserted that certain director’s discretion provisions prevent EPA and private citizens from enforcing emission limitations. See CAA §§ 113, 304. This claim suffers from a variety of errors, differing from State to State. To start, at least one of the provisions does not involve enforcement discretion at all. Ohio Admin. Code 3745-15-06(A)(3) merely allows the State to approve requests to continue source operations while conducting maintenance of pollution control equipment—it plainly does not allow exceeding applicable emission limitations. Ohio Comment 3-4, JA __. Indeed, Ohio has always interpreted this provision not to exempt emissions from applicable limitations or bar EPA or citizens from enforcing violations. In keeping with this understanding, Ohio instructs sources when it approves maintenance requests that all excess emissions are violations, and that its approval does not excuse them. Id. EPA declared the provision deficient anyway, complaining only that it was not as clearly worded as EPA would like: “The state official’s grant of permission to continue to operate during the period of maintenance could be interpreted to excuse excess emissions . . . and could thus be read to preclude enforcement by the EPA or citizens.” Comment Response 70, JA __ (emphasis added). But see supra pp. 19-21 (explaining that potential inadequacy is not substantial inadequacy). Because the plain language of Ohio Admin. Code 3745-1506(A)(3) does not permit EPA’s strained interpretation, the interpretation is arbitrary and capricious. 31 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 42 of 55 Furthermore, even where a director’s discretion provision does relate to exceedances of numerical emission limitations, EPA acknowledges that such provisions are proper if they merely guide the State’s exercise of its own enforcement. 80 Fed. Reg. at 33,919, JA __. For example, North Carolina’s SIP provides that excess SSM emissions “are considered a violation of the appropriate rule” unless the source demonstrates compliance with alternative standards to the director. 15A N.C. Admin. Code 2D0535(c), (g). As North Carolina explained, the provision governs only the director’s exercise of enforcement discretion: “Nothing in the existing SIP provisions prohibits or restricts in any way the ability of the EPA and/or a citizen to file an action in federal court seeking enforcement of the SIP provisions,” including “the state developed emission standards . . . and general and specific SSM provisions.” N.C. Comment 3, JA __. Similarly, EPA called Tennessee SIP provisions after concluding that they “could reasonably be construed” to preclude EPA and citizen enforcement, notwithstanding that Tennessee explained that the provisions guide only the State’s own enforcement discretion. See Comment Response 64, JA __; see also Tenn. Comp. R. & Regs. § 1200-03-20-.07 (setting out procedure for responding to an administrative “notice of violation,” including factors similar to those in the 1999 Memo).15 EPA’s decision to call these SIP provisions unlawfully exceeds its SIP call authority by conflating potential inadequacy with substantial inadequacy and arbitrarily 15 Moreover, sources must always avoid emissions that cause NAAQS exceedances, and the State remains free to pursue violations of any other SIP provision. Tenn. Comp. R. & Regs. § 1200-03-20-.09. 32 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 43 of 55 refusing to defer to State constructions of their SIPs that would render them consistent with EPA’s understanding of the Act’s requirements. See supra pp. 19-21. Finally, regardless of their scope, director’s discretion provisions do not immunize SSM emissions from enforcement under separate general-duty standards in a SIP, or from enforcement of standards contained in operating permits. EPA and citizens always may seek enforcement of a SIP’s generally-applicable design, equipment, work practice, or operational standards. E.g., 401 Ky. Admin. Reg. 50:055, § 5 (categorically prohibiting “air pollution” as defined by statute). They also may seek enforcement of standards contained in operating permits issued pursuant to the SIP. See 40 C.F.R. § 70.6(a)(1) (requiring that operating permits contain “[e]missions limitations and standards”); id. § 70.6(b) (providing for enforcement of operating permits’ terms and conditions by EPA and citizens). Furthermore, EPA and citizens may bring suit under SIP provisions that allow for direct enforcement of the NAAQS. E.g. 7 Del. Admin. Code 1103-2.0; La. Admin. Code tit. 33, pt. III, § 929; 15A N.C. Admin. Code 02D.0501(c). Because all of these provisions remain fully enforceable by EPA and others, and because nothing in the CAA requires that every emission limitation be applicable (much less enforceable) at all times, these provisions satisfy the CAA’s requirements that SIPs provide for enforcement of the NAAQS, include enforceable emission limitations, and include a program that provides for enforcement of those limitations. See CAA §§ 110(a)(1), 110(a)(2)(A), 110(a)(2)(C); cf. 33 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 44 of 55 Sierra Club, 551 F.3d at 1027 (recognizing that the CAA does not require continuous application of a single standard). For these reasons, the SIP Calls are unlawful as to director’s discretion provisions. D. The Act Permits States to Include Affirmative Defenses in SIPs. EPA also called SIPs that contained affirmative defenses.16 These SIPs fall into two categories: (1) SIPs that offer defenses to violations subject to certain criteria and (2) SIPs that offer defenses to monetary penalties only, allowing injunctive relief for the violation, subject to certain criteria. Both fall within States’ power to determine the “manner in which the [NAAQS] will be achieved,” which includes designing a “program to provide for the enforcement” of emission limitations. CAA §§ 107(a), 110(a)(2)(C). Calling both was error. First, SIPs that offer defenses to violations are permissible for the same reasons that so-called “automatic exemptions” are. If there are simultaneously operating general duties or a defense itself contains emission limitations, then the provisions would be consistent with EPA’s continuous-limitation requirement. See supra pp. 2223, 25-27. A State’s decision to allocate the burden of proof to the operator to Seven State Petitioners’ SIPs were called on this basis. See 80 Fed. Reg. at 33,962 (West Virginia), 33,962-63 (Georgia), 33,963-64 (Mississippi), 33,964 (South Carolina), 33,967 (Arkansas), 33,968-69 (Texas), 33,971-72 (Arizona), JA__. Delaware’s SIP was not called on this basis, and Delaware does not join this argument. 34 16 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 45 of 55 demonstrate a non-violation by meeting established criteria is a permissible State decision about how to design an enforcement program, CAA § 110(a)(2)(C), and EPA has identified nothing in the Act that specifically prohibits this regime. As explained below, this Court’s decision in NRDC v. EPA concerns only EPA’s authority to include an affirmative defense in a nationally-applicable emission standard; it does not impinge on States’ ability to define a violation in the first instance or to design an enforcement program for SIP limits. Second, EPA called SIPs that contained affirmative defenses to monetary penalties, notwithstanding the Fifth Circuit’s prior holding that States have the discretion to include such provisions in their SIPs. Luminant Generation Co. v. EPA, 714 F.3d 841, 853 n.9 (5th Cir. 2013) (holding that affirmative defenses to monetary penalties do “not negate the district court’s jurisdiction to assess civil penalties” under section 113(e)(1)). These affirmative defenses differ from the first category, because they treat the emissions as a violation subject to injunction, but if certain criteria are met, the source is protected from monetary penalties. EPA’s change of policy is based on this Court’s decision in NRDC v. EPA, 749 F.3d 1055 (D.C. Cir. 2014). NRDC holds that EPA does not have the authority to provide an affirmative defense to monetary penalties for violations of hazardous air pollutant standards promulgated under CAA § 112, because the Act assigns courts the jurisdiction to determine whether monetary penalties are appropriate once a violation is found. Id. at 1063 (citing CAA §§ 113(e)(1), 304(a)). NRDC did not address whether SIPs could contain 35 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 46 of 55 such affirmative defenses, and the case explicitly acknowledged the Fifth Circuit’s holding in Luminant that it was permissible for States to include affirmative defenses in SIPs. Id. at 1064 n.2. Notably, the NRDC court did not see anything in Luminant that required either distinction or disagreement; rather, it treated the case as addressing a fundamentally different question, and in fact, it is. EPA’s argument in NRDC failed not just because of sections 113(e)(1) and 304(a), but because EPA failed to identify any textual authority to create an affirmative defense. It could only identify language in CAA § 301(a)(1) allowing it to “‘prescribe such regulations as are necessary to carry out [its] functions under’ the Act,” a general assignment of authority that was not sufficiently specific to allow EPA to create affirmative defenses. NRDC, 749 F.3d at 1063. Congress, however, specifically tasked States with providing “a program to provide for the enforcement of” emission limitations. CAA § 110(a)(2)(C). Allowing States to create defenses to monetary penalties is consistent with the text of both section 113(e)(1) and section 304(a), which authorizes citizen suits. Section 304(a) allows a court to “apply any appropriate civil penalties” in a citizen suit, and section 113(e)(1) speaks to how a court should “determin[e] the amount of any penalty to be assessed.” Neither provision speaks to how to determine whether monetary penalties are “appropriate,” as distinct from the “amount” of penalties if a monetary penalty is appropriate, or more specifically, whether a State can determine that monetary penalties are not appropriate for certain SIP violations. Accordingly, contrary to EPA’s interpretation 36 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 47 of 55 of NRDC, including affirmative defenses in SIPs “does not negate the district court’s jurisdiction to assess civil penalties” in an enforcement action. Luminant, 714 F.3d at 853 n.9. III. EPA CANNOT CALL SIPS FOR REASONS IT DID NOT CLAIM CONSTITUTED SUBSTANTIAL INADEQUACIES. The SIP Call must also be vacated and remanded to the extent that EPA calls SIPs based on factors other than those on which it made findings of substantial inadequacy. It is unclear whether or to what extent EPA actually did this, but EPA should not be allowed to urge additional bases for finding substantial inadequacy here. See Council for Urological Interests v. Burwell, 790 F.3d 212, 222 (D.C. Cir. 2015) (court cannot affirm administrative action by substituting a “more adequate or proper basis”). Moreover, to the extent those factors are without basis in CAA requirements, they are unlawful. Texas, 690 F.3d at 682 (EPA cannot insist on “a standard that the CAA does not empower the EPA to enforce”). For example, EPA claims that even if Fla. Admin. Code § 62-210.700 were an alternative emission limitation, it is nonetheless problematic because it does “not apply only to ‘specific, narrowly-defined source categories using specific control strategies.’” 78 Fed. Reg. at 12,503, JA __ (quoting EPA’s revised SSM policy); see also 80 Fed. Reg. at 33,961 (asserting a similar flaw in West Virginia’s SIP). But EPA never determined that absolute compliance with its revised SSM policy was required to avoid substantial inadequacy—only that automatic exemptions, affirmative defenses and the like created substantial 37 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 48 of 55 inadequacies. See 80 Fed. Reg. at 33,927-29, JA __ (explaining EPA’s substantial inadequacy determinations). Moreover, finding substantial inadequacy would have been arbitrary, as EPA simultaneously decided to “remov[e] the word ‘must’ from the criteria” for properly designed alternative emission limitations, as the criteria were merely “recommendations to states.” 80 Fed. Reg. 33,913, JA __; see also id. (“A state may choose to consider these criteria in developing such a SIP provision.” (emphasis added)). To the extent EPA relied on such considerations in the SIP Calls, EPA’s action must be vacated. CONCLUSION The SIP Calls should be vacated as to the State Petitioners’ SIPs. Pamela Jo Bondi Attorney General State of Florida /s/Jonathan L. Williams Jonathan L. Williams Jordan E. Pratt Deputy Solicitors General Jonathan A. Glogau Chief, Complex Litigation OFFICE OF THE ATTORNEY GENERAL PL-01, The Capitol Tallahassee, Florida 32399-1050 Phone: (850) 414-3300 Fax: (850) 410-2672 jonathan.williams@myfloridalegal.com Counsel for Petitioner State of Florida 38 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 49 of 55 Luther Strange Attorney General State of Alabama Mark Brnovich Attorney General State of Arizona /s/ Andrew Brasher Andrew Brasher Solicitor General OFFICE OF THE ATTORNEY GENERAL 501 Washington Avenue Montgomery, AL 36130 Direct: 334-353-2609 Fax: 334-242-4891 /s/ Mark Brnovich Mark Brnovich Attorney General of Arizona OFFICE OF THE ATTORNEY GENERAL 1275 West Washington Phoenix, AZ 85007 Tel. (602) 542-5025 Counsel for Petitioner State of Alabama Counsel for Petitioner State of Arizona Leslie Rutledge Attorney General State of Arkansas Matthew P. Denn Attorney General State of Delaware /s/ Jamie Leigh Ewing Jamie Leigh Ewing Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL 323 Center Street, Suite 200 Little Rock, AR 72201 (501) 682-5310 (phone) (501) 682-3896 (fax) Jamie.ewing@arkansasag.gov /s/ Valerie Satterfield Edge Valerie Satterfield Edge Deputy Attorney General (DE I.D. #3937) Delaware Department of Justice 102 W. Water Street, 3rd Floor Dover, DE 19904 Counsel for Petitioner State of Delaware Counsel for Petitioner State of Arkansas 39 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 50 of 55 Samuel S. Olens Attorney General State of Georgia Derek Schmidt Attorney General State of Kansas /s/ Britt C. Grant Britt C. Grant Solicitor General Georgia Bar No. OFFICE OF THE ATTORNEY GENERAL 40 Capitol Sq. SW Atlanta, Georgia 30334 Phone: (404) 651-9453 Fax: (404) 463-1519 bgrant@law.ga.gov /s/ Jeffrey A. Chanay Jeffrey A. Chanay Chief Deputy Attorney General OFFICE OF THE ATTORNEY GENERAL 120 SW Tenth Avenue, Third Floor Topeka, Kansas 66612-1597 Phone: (785) 368-8435 jeff.chanay@ag.ks.gov Counsel for Petitioner State of Kansas Counsel for Petitioner State of Georgia Andy Beshear Attorney General Commonwealth of Kentucky Jeff Landry Attorney General State of Louisiana /s/ Andy Beshear Andy Beshear Attorney General of Kentucky OFFICE OF THE ATTORNEY GENERAL 700 Capital Avenue, Suite 118 Frankfort, Kentucky 40601 /s/ Steven B. “Beaux” Jones Steven B. “Beaux” Jones Attorney General OFFICE OF THE ATTORNEY GENERAL P.O. Box 94005 Baton Rouge, Louisiana 70804-9005 Counsel for Petitioner Commonwealth of Kentucky Counsel for Petitioner State of Louisiana 40 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 51 of 55 Jim Hood Attorney General State of Mississippi Chris Koster Attorney General State of Missouri /s/ Harold E. Pizzetta, III Harold E. Pizzetta, III Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL MSB No. 99867 U. S. Court of Appeals - D.C. Circuit No. 51936 Post Office Box 220 Jackson, Mississippi 39205 Telephone: (601) 359-3816 Facsimile: (601) 359-2003 hpizz@ago.state.ms.us /s/ Chris Koster Chris Koster Attorney General of Missouri OFFICE OF THE ATTORNEY GENERAL Supreme Court Building 207 West High Street Jefferson City, MO 65101 (573) 751-3321 Counsel for Petitioner State of Missouri Counsel for Petitioner State of Mississippi /s/ Sam M. Hayes Sam M. Hayes General Counsel Craig A. Bromby Deputy General Counsel Andrew J. Norton Deputy General Counsel North Carolina Department of Environmental and Natural Resources 215 W. Jones Street Raleigh, North Carolina 27603 sam.hayes@ncdenr.gov craig.bromby@ncdenr.gov andrew.norton@ncdenr.gov (919) 707-8600 Michael DeWine Attorney General State of Ohio /s/ Eric E. Murphy Eric E. Murphy State Solicitor OFFICE OF THE ATTORNEY GENERAL 30 E. Broad St., 17th Floor Columbus, OH 43215 Tel. (614) 466-8980 eric.murphy@ohioattorneygeneral.gov Counsel for Petitioner State of Ohio Counsel for Petitioner North Carolina Department of Environmental and Natural Resources 41 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 52 of 55 Alan Wilson Attorney General State of South Carolina /s/ P. Clayton Eubanks P. Clayton Eubanks Deputy Solicitor General OFFICE OF THE ATTORNEY GENERAL 313 N.W. 21st Street Oklahoma City, OK 73105 Tel: (405) 522-8992 Fax: (405) 522-0085 clayton.eubanks@oag.ok.gov Counsel for Petitioner State of Oklahoma /s/ J. Emory Smith, Jr. J. EMORY Smith, Jr. Deputy Solicitor General ROBERT D. COOK Solicitor General Email: BCOOK@SCAG.GOV OFFICE OF THE ATTORNEY GENERAL Post Office Box 11549 Columbia, South Carolina 29211 Phone: (803) 734-3680 Fax: (803) 734-3677 Email: ESMITH@SCAG.GOV Counsel for Petitioner State of South Carolina Marty J. Jackley Attorney General State of South Dakota Herbert H. Slatery III Attorney General and Reporter State of Tennessee /s/ Steven R. Blair Steven R. Blair Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL 1302 E. Highway 14, Suite 1 Pierre, SD 57501 Tel. (605) 773-3215 Email: steven.blair@state.sd.us /s/ Wilson S. Buntin WILSON S. BUNTIN Senior Counsel Environmental Division OFFICE OF THE TENNESSEE ATTORNEY GENERAL P.O. Box 20207 Nashville, Tennessee 37202-0207 (615) 253-5118 Counsel for Petitioner State of South Dakota Counsel for Petitioner State of Tennessee 42 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 53 of 55 Ken Paxton Attorney General State of Texas Patrick Morrisey Attorney General State of West Virginia Jeffrey C. Mateer First Assistant Attorney General James E. Davis Deputy Attorney General for Civil Litigation Priscilla M. Hubenak Chief, Environmental Protection Division /s/ Elbert Lin Elbert Lin Solicitor General OFFICE OF THE ATTORNEY GENERAL State Capitol Building 1, Room E-26 Charleston, WV 25305 (304) 558-2021 /s/ Kellie E. Billings-Ray Kellie E. Billings-Ray Assistant Attorney General kellie.billingsray@texasattorneygeneral.gov OFFICE OF THE ATTORNEY GENERAL OF TEXAS ENVIRONMENTAL PROTECTION DIVISION P.O. Box 12548, MC-066 Austin, Texas 78711-2548 Tel. (512) 463-2012 Fax. (512) 457-4638 Counsel for Petitioner State of West Virginia Counsel for Petitioner State of Texas 43 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 54 of 55 CERTIFICATE OF COMPLIANCE Pursuant to Rule 32(a)(7)(C) of the Federal Rules of Appellate Procedure and Circuit Rules 32(a)(1) and 32(a)(2)(C), I certify that the foregoing brief contains 9,433 words, as counted by a word processing system that includes headings, footnotes, quotations, and citations in the count, and therefore is within the word limit set by the Court. /s/ Jonathan L. Williams Jonathan L. Williams 44 USCA Case #15-1166 Document #1604344 Filed: 03/16/2016 Page 55 of 55 CERTIFICATE OF SERVICE I certify that, on this 16th day of March, 2016, a copy of the foregoing Opening Brief of State Petitioners was served electronically through the Court’s CM/ECF system on all ECF-registered counsel. /s/ Jonathan L. Williams Jonathan L. Williams 45 NO. In the Supreme Court of the United States STATE OF OKLAHOMA; OKLAHOMA INDUSTRIAL ENERGY CONSUMERS; OKLAHOMA GAS AND ELECTRIC COMPANY, Petitioners, v. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY; SIERRA CLUB, Respondents. On Petition for Writ of Certiorari to the United States Court of Appeals for the Tenth Circuit PETITION FOR WRIT OF CERTIORARI Michael Graves Thomas P. Schroedter HALL ESTILL, Attorneys at Law 320 South Boston Ave. Suite 200 Tulsa, OK 74103 (918) 594-0443 Attorneys for Petitioner Oklahoma Industrial Energy Consumers E. Scott Pruitt Oklahoma Attorney General Patrick R. Wyrick Solicitor General Counsel of Record P. Clayton Eubanks Deputy Solicitor General OKLAHOMA ATTORNEY GENERAL’’S OFFICE 313 NE 21st Street Oklahoma City, OK 73105 (405) 521-3921 patrick.wyrick@oag.ok.gov Attorneys for Petitioner State of Oklahoma (additional counsel listed on inside cover) Becker Gallagher · Cincinnati, OH · Washington, D.C. · 800.890.5001 Brian J. Murray Charles T. Wehland Dennis Murashko JONES DAY 77 West Wacker Drive Chicago, IL 60601 (312) 782-3939 Michael L. Rice JONES DAY 717 Texas, Suite 3300 Houston, TX 77002 (832) 239-3640 Attorneys for Petitioner Oklahoma Gas And Electric Company i QUESTION PRESENTED The Regional Haze Program of the Clean Air Act allocates to the States the task of fashioning and then implementing plans to improve the aesthetic quality of air over certain federal lands. The question presented is whether, despite that allocation of powers to the States, the United States Environmental Protection Agency may nonetheless conduct a de novo review of the State of Oklahoma’’s plan, in conflict with both the limited authority granted to the agency under the Act and decisions of this and other courts that have recognized the primary role given to the States in implementing the Clean Air Act. ii PARTIES TO THE PROCEEDINGS Petitioners State of Oklahoma, Oklahoma Gas and Electric Company, and Oklahoma Industrial Energy Consumers were petitioners in the court below. Respondents are the United States Environmental Protection Agency and the Sierra Club, and were respondent and intervenor-respondent, respectively, in the court below. iii RULE 29.6 STATEMENT Oklahoma Gas and Electric Company is a whollyowned subsidiary of OGE Energy Corp. No publicly held corporation owns 10% or more of the stock of OGE Energy Corp. Petitioner Oklahoma Industrial Energy Consumers is a non-partisan, unincorporated association of large consumers of energy with facilities located in the State of Oklahoma. iv TABLE OF CONTENTS QUESTION PRESENTED . . . . . . . . . . . . . . . . . . . . i PARTIES TO THE PROCEEDINGS . . . . . . . . . . . . ii RULE 29.6 STATEMENT . . . . . . . . . . . . . . . . . . . . iii TABLE OF AUTHORITIES . . . . . . . . . . . . . . . . . . vi PETITION FOR A WRIT OF CERTIORARI . . . . . . 1 OPINIONS BELOW . . . . . . . . . . . . . . . . . . . . . . . . . 1 JURISDICTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 STATUTES AND REGULATIONS INVOLVED . . . 1 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 STATEMENT OF THE CASE . . . . . . . . . . . . . . . . . 5 REASONS FOR GRANTING THE WRIT . . . . . . . 16 I. The Tenth Circuit’’s decision conflicts with decisions of this Court and other federal courts of appeal on the allocation of federalstate authority. . . . . . . . . . . . . . . . . . . . . . . . 16 II. The conflict over federal-state authority is a recurring problem of national importance. . 24 CONCLUSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 v APPENDIX Appendix A Denial of Petitions for Review of Final Decision Issued by the United States Environmental Protection Agency and Judgment in the United States Court of Appeals for the Tenth Circuit (July 19, 2013) . . . . . . . . . . . . . . . App. 1 Appendix B Final Rule, Environmental Protection Agency, 40 CFR Part 52 (December 28, 2011) . . . . . . . . . App. 56 Appendix C Order Denying Rehearing in the United States Court of Appeals for the Tenth Circuit (October 31, 2013) . . . . . . . . . . App. 209 Appendix D Statutes and Regulations . . . . App. 211 42 U.S.C.A. § 7491 . . . . . . . . . . App. 211 40 C.F.R. § 51.308 . . . . . . . . . . App. 218 Appendix E Excerpts from Regional Haze Implementation Plan Revision, State of Oklahoma, Department of Environmental Quality (February 2, 2010) . . . . . . . . . . App. 244 Appendix F Order in the United States Court of Appeals for the Tenth Circuit (June 22, 2012) . . . . . . . . . . . . . App. 246 vi TABLE OF AUTHORITIES CASES Alaska Dep’’t of Envtl. Conservation v. EPA, 540 U.S. 461 (2004) . . . . . . . . . . . . . . . . 19, 20, 26 Am. Corn Growers Ass’’n v. EPA, 291 F.3d 1 (D.C. Cir. 2002) . . . . . . . . . . . 8, 16, 17 Arizona v. EPA, No. 13-70366 (9th Cir., filed Jan. 31, 2013) . . . 25 Arizona Pub. Serv. Co. v. EPA, 562 F.3d 1116 (10th Cir. 2009) . . . . . . . . . . . . . 21 Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837 (1984) . . . . . . . . . . . . . . . . . . . . . . 16 Cliffs Natural Res., Inc. v. EPA, No. 13-1758 (8th Cir., filed Apr. 4, 2013) . . . . . 25 EME Homer City Generation, L.P. v. Envtl. Prot. Agency, 696 F.3d 7 (D.C. Cir. 2012) . . . . . . . . . . . . . . . . . 8 Louisiana Dep’’t of Env. Quality v. EPA, No. 12-60672 (5th Cir., filed Sept. 4, 2012) . . . 25 Martinez, et al. v. EPA, No. 11-9567 (10th Cir., filed Oct. 21, 2011) . . . 25 Michigan v. EPA, No. 13-2130 (8th Cir., filed May 22, 2013) . . . . 25 Nebraska v. EPA, No. 12-3084 (8th Cir., filed Sept. 4, 2012) . . . . 25 vii New York v. United States, 505 U.S. 144 (1992) . . . . . . . . . . . . . . . . . . . 26, 27 N. Dakota v. EPA, 730 F.3d 750 (8th Cir. 2013) . . . . . . . . . . . . 25, 26 PPL Montana, LLC v. EPA, No. 12-73757 (9th Cir., filed Nov. 16, 2012) . . . 25 Train v. Nat. Res. Def. Council, Inc., 421 U.S. 60 (1975) . . . . . . . . . . . . . . . . . . . 2, 8, 18 Union Elec. Co. v. EPA, 427 U.S. 246 (1976) . . . . . . . . . . . . . . . . . . . . 8, 18 Utah v. EPA, No. 13-9535 (10th Cir., filed Mar. 21, 2013) . . . 25 STATUTES, REGULATIONS, AND LEGISLATION 28 U.S.C. § 1254(1) . . . . . . . . . . . . . . . . . . . . . . . . . . 1 40 C.F.R. pt. 51 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 40 C.F.R. § 51.308 . . . . . . . . . . . . . . . . . . . . . . . . 4 40 C.F.R. § 51.308(d)(1)(i)(B) . . . . . . . . . . . . . . . . 7 40 C.F.R. § 51.308(e)(1)(ii)(A) . . . . . . . . . . . 3, 6, 8 70 Fed. Reg. 39,104 (July 6, 2005) . . . . . . . . . 2, 7 40 C.F.R. pt. 52 76 Fed. Reg. 81,728 (Dec. 28, 2011) . . . . . . 12, 13 42 U.S.C. § 7401(a)(3) . . . . . . . . . . . . . . . . . . . . . . . . 2 42 U.S.C. § 7407 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 42 U.S.C. § 7410 . . . . . . . . . . . . . . . . . . . . . . . . . . 1, 8 42 U.S.C. § 7491 . . . . . . . . . . . . . . . . . . . . . . . . . . 1, 3 viii 42 U.S.C. § 7491(a)(1) . . . . . . . . . . . . . . . . . . . . . . 2, 5 42 U.S.C. § 7491(b)(1) . . . . . . . . . . . . . . . . . . . . . . . . 7 42 U.S.C. § 7491(b)(2) . . . . . . . . . . . . . . . . . . . . . . . . 7 42 U.S.C. § 7491(b)(2)(A) . . . . . . . . . . . . . . . . . . . . . 6 42 U.S.C. § 7491(g)(2) . . . . . . . . . . . . . . . . . . . . 3, 5, 6 70 Fed. Reg. 39,106/1-2 . . . . . . . . . . . . . . . . . . . . . . . 8 70 Fed. Reg. 39,107/3 . . . . . . . . . . . . . . . . . . . . . . . . 8 70 Fed. Reg. 39,127 . . . . . . . . . . . . . . . . . . . . . . . . . 13 70 Fed. Reg. 39,132 . . . . . . . . . . . . . . . . . . . . . . . . . 10 70 Fed. Reg. 39,137 (July 6, 2005) . . . . . . . . . . . . . . 2 76 Fed. Reg. 52,388 (Aug. 22, 2011) (New Mexico) . 25 76 Fed. Reg. 81,728 (Dec. 28, 2011) (Oklahoma) . . 25 77 Fed. Reg. 14,604 (Mar. 12, 2012) (Arkansas) . . 25 77 Fed. Reg. 20,894 (Apr. 6, 2012) (North Dakota) 25 77 Fed. Reg. 33,022 (June 4, 2012) (Wyoming) . . . 25 77 Fed. Reg. 39,425 (July 3, 2012) (Louisiana) . . . 25 77 Fed. Reg. 40,150 (July 6, 2012) (Nebraska) . . . 25 77 Fed. Reg. 50,936 (Aug. 23, 2012) (Nevada) . . . . 25 77 Fed. Reg. 57,864 (Sept. 18, 2012) (Montana) . . 25 77 Fed. Reg. 71,533 (Dec. 3, 2012) (Michigan) . . . . 25 77 Fed. Reg. 72,512 (Dec. 5, 2012) (Arizona) . . . . . 25 ix 77 Fed. Reg. 74,355 (Dec. 14, 2012) (Utah) . . . . . . 25 78 Fed. Reg. 8,706 (Feb. 6, 2013) (Minnesota) . . . . 25 Alaska National Interest Lands Conservation Act, 16 U.S.C. §§ 3101 et seq. . . . . . . . . . . . . . . . . . . 26 Clean Air Act, 42 U.S.C. § XXX . . . . . . . . . . . passim § 7410 (sec. 110) . . . . . . . . . . . . . . . . . . . . . . . . . . 1 § 110(a)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 § 7491 (sec. 169A) . . . . . . . . . . . . . . . . . . . . . . . . 1 § 7492 (sec. 169B) . . . . . . . . . . . . . . . . . . . . . . . . 1 § 169A(b)(2)(A) . . . . . . . . . . . . . . . . . . . . . . . 17 § 169A(g)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Clean Water Act, 33 U.S.C. §§ 1251 et seq. . . . . . . 26 Occupational Safety and Health Act, 29 U.S.C. §§ 651 et seq. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Resource Conservation and Recovery Act, 42 U.S.C. §§ 6901 et seq. . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 OTHER AUTHORITIES http://www.epa.gov/airquality/visibility/what.html. 2 Oklahoma Regional Haze State Implementation Plan, available at http://www.deq.state.ok.us/ AQDnew/rulesandplanning/Regional_Haze/SIP /index.htm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1 PETITION FOR A WRIT OF CERTIORARI __________ Petitioners respectfully pray for a writ of certiorari to review the judgment of the United States Court of Appeals for the Tenth Circuit in this case. OPINIONS BELOW A divided panel of the Tenth Circuit filed its opinion on July 19, 2013. App. 1. That opinion is reported at 723 F.3d 1201. JURISDICTION The judgment of the court of appeals was entered on July 19, 2013. Petitions for panel and en banc rehearing were denied on October 31, 2013. App. 209. This petition for certiorari is filed within ninety days of the denial of the petitions for rehearing. The jurisdiction of this Court is invoked under 28 U.S.C. § 1254(1). STATUTES AND REGULATIONS INVOLVED This case involves a challenge to a final rule that the United States Environmental Protection Agency (““EPA””) promulgated under sections 110, 169A and 169B of the Clean Air Act, 42 U.S.C. §§ 7410, 7491, 7492. EPA published the final rule on December 28, 2011, at 76 Fed. Reg. 81,728. Also involved are regulations that EPA promulgated to effectuate the relevant sections of the Clean Air Act. Those regulations are found at 40 C.F.R. pt. 51, subpt. P. The full text of pertinent statutory and regulatory provisions are set forth in the appendix to this petition. App. 211. 2 INTRODUCTION This case raises recurring issues of national importance concerning the ability of the States to exercise their statutory authority under the Clean Air Act’’s ““Regional Haze Program””——a program that affects forty-five States and territories. The Regional Haze Program was added to the Clean Air Act in 1977, and aims to mitigate and ultimately prevent any ““impairment of visibility in mandatory Class I Federal areas”” due to ““manmade air pollution.”” 42 U.S.C. § 7491(a)(1).1 The Clean Air Act recognizes that ““air pollution prevention . . . and air pollution control at its source is the primary responsibility of States and local governments.”” 42 U.S.C. § 7401(a)(3); see also id. § 7407(a). Even in the Clean Air Act, where cooperative federalism is a dominant theme, the Regional Haze Program is unique in the amount of power reserved to the States. See, e.g., Train v. Natural Resources Defense Council, Inc., 421 U.S. 60, 79 (1975); 70 Fed. Reg. 39,104, 39,137 (July 6, 2005) (““the Act and legislative history indicate that Congress evinced a special concern with insuring that States would be the decision makers.””). Congress was especially concerned with maximizing state authority in this context 1 According to EPA, ““[h]aze is caused when sunlight encounters tiny pollution particles in the air. Some light is absorbed by particles. Other light is scattered away before it reaches an observer. More pollutants mean more absorption and scattering of light, which reduce the clarity and color of what we see. Some types of particles such as sulfates, scatter more light, particularly during humid conditions.”” See http://www.epa.gov/ airquality/visibility/what.html. 3 because the Regional Haze Program’’s goals and standards are purely aesthetic, unrelated to public health and safety. Congress thus vested the States——not EPA——with the authority to develop and implement ““State Implementation Plans”” under the Regional Haze Program that include ““reasonable progress”” measures and ““best available retrofit technology”” (““BART””) determinations (i.e., determinations as to what technology might best control emissions from certain qualifying sources, like electricity generating plants). See 42 U.S.C. § 7491. Congress further mandated that States, not EPA, decide what constitutes BART for eligible facilities. See 42 U.S.C. § 7491(g)(2). And the Clean Air Act does not require the State to reach any particular result in doing so; rather, it only requires that the State balance five statutory factors, and reach a decision of its own based on that balancing. 42 U.S.C. § 7491(g)(2); 40 C.F.R. § 51.308(e)(1)(ii)(A). Oklahoma’’s Regional Haze State Implementation Plan accordingly balanced the five BART factors, and determined that the BART for reducing sulfur dioxide (SO2) emissions from its six qualifying sources (i.e., electricity-generating power plants) was to require those facilities to use only low sulfur coal, which burns significantly cleaner than cheaper high sulfur coal, and emits about fifty percent less SO2. Oklahoma submitted its Plan to EPA with this BART determination for SO2. Under the guise of reviewing Oklahoma’’s BART determination for compliance with the statutory requirement that Oklahoma balance the five prescribed factors, EPA conducted a de novo review of those determinations and rejected Oklahoma’’s Plan. EPA 4 then substituted a Federal Implementation Plan in place of Oklahoma’’s Plan that required the power plants to reduce SO2 emissions to virtually zero. Without this Court’’s intervention, Petitioner Oklahoma Gas and Electric Company (““OG&E””) must either convert its power plants to natural gas long before necessary or install ““scrubbers”” onto them, at an estimated cost of $1.2 billion. Worse still, EPA admits that either option will result in visibility improvements that are barely perceptible to the human eye. A divided panel of the Tenth Circuit held that not only did EPA have the authority to review and reject Oklahoma’’s Plan, but that EPA’’s reasoning in doing so was entitled to highly deferential ““arbitrary and capricious”” review. That decision is unquestionably wrong, and demands this Court’’s urgent review. In overriding Oklahoma’’s BART determination in this manner, EPA usurped authority that the Clean Air Act clearly delegates to the States, upsetting the balance of power that Congress carefully sought to create in the Clean Air Act and its Regional Haze Program. And in conflict with decisions of other courts recognizing the proper allocation of authority under the Clean Air Act, the Tenth Circuit sanctioned that result, reflexively deferring not to the States, as the Regional Haze Program required, but to EPA. The Tenth Circuit’’s decision threatens every State’’s ability to exercise the statutory authority vested in them by Congress to make BART determinations under the Regional Haze Program. And the threat runs deeper. The same question of understanding, respecting, and implementing the shared authority between the States and the federal government arises 5 under a broad range of other federal statutes with a similar cooperative-federalism approach. The Court should resolve the question presented without delay. Waiting for further percolation is not a practical option, as the multi-billion dollar federal plans that are being foisted upon the States cannot practically be undone once implementation has begun, and at least nine other States have had their State Implementation Plans rejected and replaced with Federal Implementation Plans. In Oklahoma alone, EPA’’s actions will cost OG&E $1.2 billion dollars with no discernable return other than a marked increase in what Oklahoma ratepayers will pay for their electricity. Accordingly, this Court’’s immediate review is urgently needed to preserve the delicate balance of power that Congress established in the Regional Haze Program (and other federal statutes that reflect similar divisions of authority) and to settle this important issue that will recur time and again as Regional Haze State Implementation Plans are reviewed throughout the nation. STATEMENT OF THE CASE Statutory and Regulatory Background. In unequivocal terms, Congress intended that the States would implement the Regional Haze Program’’s aesthetic goal of ““remedying . . . impairment of visibility in mandatory class I Federal areas.”” 42 U.S.C. § 7491(a)(1), (g)(2). As such, the Clean Air Act mandates that a State submit a Plan to EPA laying out the State’’s plan for achieving that goal. The Clean Air Act requires that, with regard to certain sources that contribute to visibility impairments, State Implementation Plans must include: 6 except as otherwise provided . . . a requirement that each major stationary source which is in existence on August 7, 1977, but which has not been in operation for more than fifteen years as of such date, and which, as determined by the State (or the Administrator in the case of a [Federal Implementation Plan]) emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area, shall procure, install, and operate, as expeditiously as practicable (and maintain thereafter) the best available retrofit technology, as determined by the State (or the Administrator in the case of a [Federal Implementation Plan]) for controlling emissions from such source for the purpose of eliminating or reducing any such impairment. § 7491(b)(2)(A) (emphases added). The twice-deployed phrase ““as determined by the State”” is unambiguous. In other words, the State——not EPA——must: 1) determine which of the eligible major stationary sources in the State contribute to visibility impairment; and then 2) determine BART for controlling the emissions causing that impairment at that source. Id. When determining BART, the State must balance five factors for each qualifying source: (i) the costs of compliance; (ii) the energy and non-air quality environmental impacts of compliance; (iii) any existing pollution control technology in use at the source; (iv) the remaining useful life of the source; and (v) the degree of improvement in visibility that may be expected as a result of such technology. 42 U.S.C. § 7491(g)(2); 40 C.F.R. § 51.308(e)(1)(ii)(A). 7 The EPA’’s role, in turn, is limited to ensuring that each state plan ““contain[s] such emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward meeting the national goal.”” § 7491(b)(2). To carry out this limited role, EPA is tasked with creating guidelines for the States ““on appropriate techniques and methods for implementing this section.”” § 7491(b)(1). To this end, the Clean Air Act advises EPA that State Implementation Plans must contain ““such emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward meeting”” the national visibility goal. § 7491(b)(2).2 EPA has thus promulgated ““Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule.”” (““BART Guidelines””). 70 Fed. Reg. 39,104 (July 6, 2005) (codified at 40 C.F.R. pt. 51). Pursuant to the Clean Air Act, a State must apply the BART Guidelines only when a State makes a BART determination for a powerplant of at least 750MW. For sources under 750MW, the Guidelines become discretionary. As the BART determinations at issue in Oklahoma were for sources greater than 750MW, Oklahoma was obligated to apply the BART Guidelines. 2 In its regulations, EPA established that the goal of natural visibility conditions be attained by the year 2064. 40 C.F.R. §51.308(d)(1)(i)(B). BART is just the first of the reasonable progress control measures to be employed over the course of the sixty-year Visibility Program. 8 In the Guidelines, EPA acknowledges that it is the States that identify which BART sources ““may reasonably be anticipated to cause or contribute to any impairment of visibility in any mandatory Class I Federal area,”” 70 Fed. Reg. 39,106/1-2, and it is the States who ““must determine the appropriate level of BART control for each source subject to BART.”” 70 Fed. Reg. 39,107/3. In short, as emphasized by the D.C. Circuit, the Clean Air Act ““give[s] the States broad authority over BART determinations”” and how a state weighs the BART factors. Am. Corn Growers Ass’’n v. EPA, 291 F.3d 1, 8 (D.C. Cir. 2002). The bottom line is EPA may only reject a State’’s determination when it finds that the State’’s determination does not accomplish the goals of the Regional Haze Program. See 42 U.S.C. § 7410; 40 C.F.R. 51.308(e)(1)(ii)(A). The Clean Air Act ““gives the [EPA] no authority to question the wisdom of a State’’s choices of emission limitations”” if such choices are ““part of a plan which satisfies the standards of § 110(a)(2).”” Train, 421 U.S. 60, 79; see also Union Elec. Co. v. EPA, 427 U.S. 246, 250 (1976) (the Clean Air Act provides that EPA ““shall approve the proposed plan if it has been adopted after public notice and hearing”” and if it meets the ““specified criteria”” set forth in Clean Air Act § 110(a)(2)). In short, the division of authority between EPA and the States ““is strict,”” and establishes a ““federalism bar.”” EME Homer City Generation, L.P. v. EPA, 696 F.3d 7, 29 (D.C. Cir. 2012). This ““statutory federalism bar prohibits EPA from using the [State Implementation Plan] process to force States to adopt specific control measures.”” Id. 9 Factual Background. Oklahoma contains a single area subject to the Regional Haze Program: the Wichita Mountains National Wildlife Refuge, which makes up a portion of a small mountain range in sparsely populated far southwestern Oklahoma. As required by the Regional Haze Program, Oklahoma identified six major stationary sources as contributing to visibility impairment at the Wildlife Refuge——two units at OG&E’’s Muskogee Generating Station, two units at its Sooner Generating Station, and two units owned and operated by Public Service Company of Oklahoma.3 The units are located in northeastern Oklahoma. The closest is 145 miles from the Wildlife Refuge, while the farthest is 201 miles away. Petitioner OG&E is Oklahoma’’s largest electricity provider and serves approximately 785,000 customers over 30,000 square miles in Oklahoma and western Arkansas. Another Petitioner, Oklahoma Industrial Energy Consumers, represents many of Oklahoma’’s largest consumers of electricity——mainly industrial consumers engaged in energy price-sensitive industries such as pulp and paper, cement, refining, glass, industrial gases, plastic, film and food processing, and who employ thousands of Oklahoma citizens. Both OG&E and the Oklahoma Industrial Energy Consumers participated in Oklahoma’’s State Implementation Plan process. Oklahoma’’s State Implementation Plan. When Oklahoma began the process of determining BART for its six qualifying sources, before it were both a 2008 3 The Public Service Company of Oklahoma reached a negotiated settlement with EPA. Its two units are not at issue. 10 cost analysis for the OG&E Units——which both EPA and the Oklahoma Department of Environmental Quality had stated was prepared in conformity with EPA Air Pollution Control Cost Manual——and a 2009 cost analysis prepared at EPA’’s and Oklahoma’’s request that was more site-specific than the 2008 cost estimate. Oklahoma’’s ““on the ground”” analyses demonstrated that the installation of scrubbers on each of the four OG&E Units would cost more than $1.2 billion, or between approximately $7,000 and $10,000 per ton of SO2 removed, which is between three and one-half and five times the upper limit of EPA’’s expected costs for this technology. See 70 Fed. Reg. at 39,132 (estimating an average cost of $919 per ton and a cost range of $400 to $2,000 per ton of SO2 removed). Additionally, because OG&E had voluntarily begun using low sulfur coal some years prior, the effectiveness of scrubbers to reduce actual SO2 emissions was greatly reduced. The State unequivocally concluded that scrubbers were not cost effective for the OG&E Units. Not only were the scrubbers too expensive in light of the minimal visibility benefits that would result from their use, but their high costs would compel OG&E to extend the life of the coal-fired units to allow it to recoup the enormous capital costs. A broad spectrum of other parties, such as environmental advocates like the Oklahoma Chapter of the Sierra Club, supported the State’’s conclusion at the time. Oklahoma concluded that making the continued use of low sulfur coal mandatory constituted BART for SO2 emissions from the OG&E Units. Oklahoma determined that this requirement would result in an 11 annual average SO2 emission rate of 0.55 lb/mmBtu, less than half the average annual emission rate of 1.176 lb/mmBtu that EPA projected if cheaper high sulfur coal was used. On February 17, 2010, Oklahoma submitted to EPA its State Implementation Plan containing these BART determinations. Oklahoma explained in its Plan that: [Oklahoma] conducted a thorough case-by-case five-factor BART analysis for each of the BARTsubject units. [Oklahoma] determined that [scrubbers are] not cost-effective for SO2 control for any of the six coal-fired . . . electric units reviewed. . . . This determination is based on the capital cost of add-on controls, the cost effectiveness both in dollars per ton and dollars per deciview of add-on controls, the long term viability of coal with respect to other environmental programs, and national commitments. . . . Revised cost estimates were provided by the affected facilities that are based on vendor quotes and go well beyond the default methodology recommended by EPA guidance. The cost estimates are credible, detailed, and specific for the individual facilities. The final estimate for [scrubbers] for the six coal-fired units was on average 153% greater than the high end costs assumed by [Oklahoma] in the Draft [State Implementation Plan]. These costs put the projects well above costs reported for other BART determinations, and above the levels [Oklahoma] considered reasonable for cost effectiveness both in terms of dollars per ton of 12 pollutant removed and dollars per deciview (e.g., $10,000,000/dv) of improved visibility. (Oklahoma Regional Haze State Implementation Plan), App. 245 (available at: http://www.deq.state.ok.us/ AQDnew/rulesandplanning/Regional_Haze/SIP/index .htm) (emphasis added). EPA’’s Rejection of Oklahoma’’s Plan. On December 28, 2011, EPA published a final rule with respect to the Oklahoma Plan, disapproving the State’’s SO2 BART determinations for the six Oklahoma units based on EPA’’s own balancing of the five statutory factors. See Partial Approval of Oklahoma State Implementation Plan and Promulgation of Federal Implementation Plan, 76 Fed. Reg. 81,728 (Dec. 28, 2011) (““Final Rule””); App. 56. Instead of accepting Oklahoma’’s approach, EPA implemented a markedly different approach through a Federal Implementation Plan that imposed a 30-day average SO2 emission limit of 0.06 lbs/MMBtu for each of the four OG&E Units. App. 70. If OG&E wishes to continue to operate the four affected coal units, the limit imposed by EPA in the Final Rule would require the installation of a scrubber at each unit within five years. To justify rejecting Oklahoma’’s Plan, EPA hired its own analyst who expressly and remarkably: 1. assumed that OG&E was burning highsulfur coal, even though that had not been the case for years, and despite the fact that EPA’’s own BART Guidelines mandated the use of actual historic baseline emissions, App. 139; 13 2. assumed that OG&E could use smaller, cheaper scrubbers, despite the fact that OG&E showed that those smaller scrubbers would act as governors on its units and prevent the units from producing enough electricity to meet peak demand, id.; 3. concluded that the useful life of the scrubbers was thirty years——rather than the twentyyear useful life used by Oklahoma——despite the fact that EPA had itself used twenty years in prior cost analyses, App. 159; and 4. rejected Oklahoma’’s cost estimates for deviating from EPA’’s Control Cost Manual, even though EPA had previously acknowledged that ““States have flexibility in how they calculate costs,”” 70 Fed. Reg. at 39127, and the State had real-world, sitespecific vendor quotes to support those estimates. App. 135-36. Ironically, EPA then turned around and itself deviated from the Control Cost Manual without any sitespecific cost support in estimating much lower installation costs. In short, EPA’’s analyst dramatically overstated the cost-effectiveness of the scrubbers. EPA, in turn, used the analyst’’s conclusions as a basis for rejecting Oklahoma’’s Plan. Worse still, EPA’’s final rule for the first time employed the ““overnight method”” for calculating costs (i.e., assuming that an entire plant could be constructed in a single day) and the days of visibility improvement metric for conducting visibility analysis (a cumulative analysis that fails to perform the required analysis for each source), depriving 14 petitioners of the opportunity to comment on those new methodologies. Petitioners filed requests for reconsideration with EPA in February 2012, but no action has been taken on those requests. Proceedings Below. On February 24, 2012, Petitioners filed petitions for review challenging EPA’’s partial disapproval of the Oklahoma Plan and simultaneous promulgation of EPA’’s Federal Implementation Plan as arbitrary and capricious, contrary to law, and in violation of the Administrative Procedure Act’’s notice-and-comment requirements.4 On June 22, 2012, the Tenth Circuit issued an order to stay the Federal Implementation Plan pending the hearing by the merits panel. App. 246. A divided panel of the Tenth Circuit subsequently denied the petitions for review. Reasoning that ““all the [Clean Air Act] did was shift the initial responsibility for making BART determinations from EPA to the State,”” App. 16 (emphasis added), the majority concluded that not only was Oklahoma entitled to no deference in its initial BART determination, but that EPA was entitled to deference in ““reviewing”” and rejecting Oklahoma’’s Plan. App. 19-20. The majority thus reviewed EPA’’s rejection of Oklahoma’’s Plan to see if it was ““arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.”” Id. In applying that review, the majority noted that the 4 The Tenth Circuit consolidated for review the separate petitions filed by the State of Oklahoma and Oklahoma Industrial Energy Consumers (No. 12-9526) and OG&E (No. 12-9527). 15 deference it afforded to EPA was ““especially strong”” because the challenged decisions involved technical matters within EPA’’s area of expertise, and, therefore, ““[l]eft to evaluate the arguments of the parties’’ experts, we must give deference to the EPA.”” App. 32-33. Even affording such deference to EPA, the majority thought it a ““close case,”” but in its view, it ““ultimately”” could not adopt Oklahoma’’s analyses ““given that the EPA was aware of, and provided explanations contradicting, petitioners’’ comments.”” App. 33. Turning to EPA’’s Federal Implementation Plan, the majority applied ““the same arbitrary and capricious standard……used to evaluate the EPA’’s rejection of [Oklahoma’’s Plan],”” App. 28-29, and concluded that the Federal Implementation Plan was neither arbitrary nor capricious. App. 28-45. Judge Kelly dissented, expressing the view that while ““[u]sually the court grants deference to the EPA’’s technical determinations……[t]he EPA deserves no such deference, however, where it does not support a conclusion contradicting Oklahoma’’s first, reasonable, detailed technical conclusion.”” App. 52. Judge Kelly further explained that while ““the EPA has at least some authority to review BART determinations within a state’’s [Plan], it has no authority to condition approval of a [State Implementation Plan] based simply on a preference for a particular control measure.”” App. 53. Judge Kelly concluded that ““Oklahoma considered the cost and resulting benefit of such a large investment in scrubbers, and its conclusion was not unreasonable.”” Id. Judge Kelly concluded that EPA acted ““arbitrarily and capriciously”” by exaggerating the effectiveness of the scrubbers in 16 order to make them seem cost effective. EPA, ““[k]nowing these calculations violated [its own] manual,”” developed an alternative way to attempt to justify the scrubbers: it simply changed ““the size of the scrubbers to smaller, less expensive ones,”” but did so without providing ““any evidence that a significantly smaller scrubber was sufficient to meet OG&E’’s needs.”” App. 51-52. Consequently, Judge Kelly would have found EPA’’s actions unlawful and would not have deferred to EPA’’s technical judgments and experts. App. 52. Judge Kelly also concluded that EPA failed to provide record evidence to support why its own contrary BART determinations were justified. REASONS FOR GRANTING THE WRIT I. The Tenth Circuit’’s decision conflicts with decisions of this Court and other federal courts of appeal on the allocation of federalstate authority. In reflexively affording EPA Chevron deference, the panel below departed from other circuits, which have resoundingly recognized that States, not EPA, are entitled to deference in formulating plans under the Clean Air Act. Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837 (1984). The decision below radically departed from the clearlydesigned cooperative-federalism mechanism of the Clean Air Act (specifically, the Regional Haze Program), converting it into federal supremacy where EPA is permitted to replace a State’’s determination with its own. 1. The decision below squarely conflicts with the D.C. Circuit’’s decision in American Corn Growers 17 Association v. EPA, 291 F.3d 1 (D.C. Cir. 2002) (““Corn Growers””), in which the D.C. Circuit invalidated EPA’’s attempt to mandate the manner in which States must consider one of the five BART factors and stressed that EPA’’s actions were ““inconsistent with the Act’’s provisions giving the states broad authority over BART determinations.”” Id. at 8. By dictating that the States make BART determinations in a particular manner, EPA had impermissibly ““constrain[ed] authority Congress conferred on the states.”” Id. at 9. The court emphasized that the ““states . . . play the lead role in designing and implementing regional haze programs,”” id. at 8 (citing Clean Air Act §§ 169A(b)(2)(A); 169A(g)(2)), and that the phrase ““as determined by the State”” is unique to the Regional Haze Program. Indeed, no similar language appears in other air programs regarding, for example, best available control technology (““BACT””) or National Ambient Air Quality Standards. As such, the D.C. Circuit had no trouble concluding that Congress had unequivocally left BART determinations to the States. Id. at 7––8. Regardless, the panel below concluded that Corn Growers did ““not alter [its] conclusion.”” App. 14. The panel held that while Corn Growers recognized that the Clean Air Act ““shift[ed] the power to determine BART from the EPA to the states,”” Congress intended only to prevent ““the EPA from directly making t[he] BART decisions, ”” and that EPA retained the ability to indirectly make those decisions through its ““authority to ensure that……BART decisions comply with the statute.”” Id. But that is a distinction without a difference. By replacing Oklahoma’’s careful work in the State 18 Implementation Plan with EPA’’s own, de novo approach, driven by its hired consultant’’s post-State Implementation Plan work, EPA did make BART decisions directly. The fact that EPA operated under the cloak of reviewing Oklahoma’’s Plan is beside the point if, at the end of the day, the result is the same. 2. The decision below also cannot be reconciled with this Court’’s nearly four decades of recognizing the Clean Air Act’’s ““division of responsibilities”” between the States and the federal government. Train v. Natural Resources Defense Council, Inc., 421 U.S. 60, 79 (1975). In Train, the Court observed that EPA ““is plainly charged by the Act with the responsibility for setting the national ambient air standards.”” But ““[j]ust as plainly,”” EPA ““is relegated by the Act to a secondary role in the process of determining and enforcing the specific, source-by-source emission limitations which are necessary if the national standards it has set are to be met.”” Id. (emphasis added). As the Court explained, ““[t]he Act gives the [EPA] no authority to question the wisdom of a State’’s choices of emission limitations if they are part of a plan which satisfies the [Act’’s] standards.”” Id. ““[S]o long as the ultimate effect of a State’’s choice of emission limitations is compliance with the national standards for ambient air, the State is at liberty to adopt whatever mix of emission limitations it deems best suited to its particular situation.”” Id.; see also Union Elec. Co. v. EPA, 427 U.S. at 269 (““Congress plainly left with the States, so long as the national standards were met, the power to determine which sources would be burdened by regulation and to what extent””). 19 3. Likewise, the Court in Alaska Department of Environmental Conservation v. EPA, 540 U.S. 461 (2004), examined EPA’’s attempt to override Alaska’’s ““best available control technology”” (““BACT””) determination under the National Ambient Air Quality Standards program——a program in which the Clean Air Act gives EPA an even greater supervisory role than in Regional Haze cases. Despite the express authority conferred by the Clean Air Act on EPA to reject a State’’s BACT determination, this Court held that EPA’’s role was limited to reviewing whether the State’’s BACT determination was reasonably moored to the Clean Air Act and faithful to the statute’’s definition of BACT. Id. at 484. Unwilling to accord its normal deference to EPA’’s actions, this Court found that EPA’’s oversight role was limited to determining whether the State’’s determination ““is not based on a reasoned analysis”” and is ““arbitrary.”” Id. at 490-91. Even EPA agreed that it must accord appropriate deference to a State’’s determination and that it lacked authority to ““second guess”” a state’’s decision. Id. Thus, in reviewing EPA’’s purely supervisory role, this Court held that ““the production and persuasion burdens remain with EPA and the underlying question a reviewing court resolves remains the same: Whether the state agency’’s BACT determination was reasonable, in light of the statutory guides and the state administrative record.”” Id. at 494. This Court’’s reasoning in Alaska Department should have applied with even greater force to EPA’’s review of BART determinations. BACT is a continually-evolving, health-driven emission level applicable to new construction or modification. BART, on the other hand, 20 is a one-time, cost-benefit-based, visibility standard for sources constructed prior to and unmodified since 1977. The BACT provisions impose obligations reflected by such strong, normative terms as ““maximum”” and ““achievable”” that are not found in the Clean Air Act’’s definition of BART. Id. at 484––91. There is also no provision in BACT that is comparable to the Regional Haze Program’’s unequivocal mandate that BART is ““as determined by the State.”” In evaluating EPA’’s rejection of Oklahoma’’s BART determination, the panel below largely ignored Alaska Department, and disregarded its guidance. The panel sanctioned EPA’’s second-guessing of the cost estimates used in the State’’s BART determination, contending that they failed to comply with EPA guidelines. EPA erroneously argued——and the panel majority agreed——that Oklahoma failed to follow a particular costing methodology, that OG&E’’s costing assumptions were flawed, and that even OG&E’’s detailed cost estimates, provided at EPA’’s request, were inadequate. Oklahoma raised numerous objections and counterarguments to these conclusions during the Federal Implementation Plan rulemaking process, but the panel found that Oklahoma failed to show that EPA’’s approach was arbitrary and capricious. This finding requires Oklahoma to disprove the validity of EPA’’s conclusions, but Alaska Department mandates otherwise. It is EPA that bears the burden of showing that Oklahoma’’s costing methods, and ultimately its BART determination, were unreasonable, and the panel erred in holding EPA to a lesser standard. 4. Contrary to the approach taken by the majority, for regional haze, the State, not EPA, is the ““authorized 21 agency”” entitled to deference under Arizona Public Service Co. v. EPA, 562 F.3d 1116, 1123 (10th Cir. 2009). By according EPA the deference that is reserved by the Clean Air Act to the State, the panel majority’’s decision undermined the State’’s exercise of its authority under the Clean Air Act. Repeatedly throughout the course of its review of EPA’’s decision, the panel deferred to EPA’’s preferences as long as EPA’’s hired consultant provided some explanation for EPA’’s conclusions. But the test should not have been whether EPA’’s approach could be justified. It should have been whether EPA had a basis to say that the State’’s approach violated some mandatory requirement in the Regional Haze Regulations or was itself arbitrary. The panel’’s decision leaves States unable to determine with certainty what approach to regional haze is acceptable because the majority gives EPA the freedom to rely on any one of multiple possible interpretations of baseline emissions, of the requirements of EPA’’s Control Cost Manual, or even of the engineering necessary to identify technically feasible controls. By painting its review of EPA’’s action in rejecting the Oklahoma Plan with the same broad, deferential brush that it viewed EPA’’s adoption of its own Federal Implementation Plan, the panel improperly disturbed the State’’s authority to determine BART, contrary to the Clean Air Act and the long line of decisions described above. Because the majority was overly deferential in its review of EPA’’s action, it failed to conduct a meaningful examination of the explanations underlying EPA’’s cost analysis. The panel should have required EPA to show why the State’’s rule was unreasonable before EPA could reject Oklahoma’’s Plan, and the 22 panel should have done so giving deference to Oklahoma’’s determinations, not EPA’’s. If the panel had given EPA’’s rejection of Oklahoma’’s Plan that level of review, it would have found that EPA’’s explanations were frequently based on assumptions unsupported by the record, contrary to basic engineering or economic realities, or based on materials or analysis that EPA did not provide to Oklahoma as part of the state administrative record for its consideration during the State’’s lengthy process for making its BART determination. This aspect of the decision is particularly important because the majority recognized that even under its deferential standard of review, it was a ““close case.”” The panel’’s wholesale deference allowed EPA to: 1. ignore technical design requirements for the scrubbers needed to maintain the existing functionality of the OG&E Units and ignored EPA’’s own guidelines requiring the use of past actual emissions to measure the effect of the addition of scrubbers. 2. deviate from the twenty-year useful life of scrubbers used by Oklahoma even though a twenty-year life has been used in other cost analyses and has been acknowledged by EPA as being consistent with its Control Cost Manual. That error alone resulted in understating the scrubber’’s annual capital costs by thirty percent. 3. reject Oklahoma’’s 2009 cost estimates that deviated from the Control Cost Manual even though the State had site-specific vendor quotes to support those costs. Meanwhile, 23 EPA deviated from the Control Cost Manual without any site-specific cost support. 4. support the Federal Implementation Plan by aggregating visibility improvements from multiple units, even though OG&E specifically objected to that methodology in the administrative proceeding for being inconsistent with the Regional Haze regulations. EPA could not justify its rulemaking and achieve its desired result of requiring scrubbers on the OG&E Units without these errors because OG&E voluntarily adopted the use of low sulfur coal many years ago, thus minimizing any adverse impact on visibility. The Oklahoma Plan would have ensured reasonable further progress toward maintaining that limited impact by making that voluntary choice mandatory. EPA, however, was unsatisfied with anything less than the installation of scrubbers, which put it in the awkward position of having to justify huge costs from which only marginal visibility benefits will flow. It was thus little wonder EPA’’s rulemaking was not a model of expert agency work. The only question for EPA on review of the State’’s determination should have been whether it represented a reasonable application of EPA guidelines based on the record that existed when the State made its decision, and in conducting this review, EPA should have given the State’’s determinations the same level of deference that it expects when its decisions are reviewed. Rather than review the State’’s determination for proper and reasonable exercise of its discretion, EPA hired a consultant to second-guess Oklahoma’’s 24 choices, App.9, created projections of scrubber costs using its discretionary choices and assumptions after the state administrative record was closed, id., and substituted its judgments for the site-specific analysis conducted by Oklahoma. EPA did not give Oklahoma this information to consider in making its BART determination. The Clean Air Act does not authorize EPA to approach its review of the State’’s BART determinations in that way, and the majority’’s decision undermines the authority given to the State. On this basis alone, this Court’’s review is warranted and urgently needed. II. The conflict over federal-state authority is a recurring problem of national importance. This Court’’s review is urgently needed in light of the important and recurring nature of the question presented——not only under the Regional Haze Program but also a broad range of other federal statutes exemplifying various allocations of authority between the States and federal government. 1. In this, just the first phase of the long-term Regional Haze Program,5 EPA has disapproved state BART determinations or taken similar action in twelve States and has a pending disapproval in another 5 Given the stringency of EPA’’s other regulations applicable to facilities in the eastern States, EPA has not for the most part required those States to make BART determinations for electricity generating sources. 25 State.6 While the Tenth Circuit’’s decision was the first of multiple expected judicial decisions reviewing EPA disapprovals of state BART determinations under the Regional Haze Program in circuits around the country, it will certainly not be the last. At least nine other proceedings are now pending, involving seven other state plans, including two more in the Tenth Circuit.7 And more may be yet to come. Just as it rushed to do in North Dakota’’s case before the Eighth Circuit, EPA will certainly waste no time in using the Tenth Circuit’’s decision before court after court in these BART cases. And if those courts rely on the Tenth Circuit’’s decision like the Eighth Circuit did, 6 77 Fed. Reg. 72,512 (Dec. 5, 2012) (Arizona); 77 Fed. Reg. 14,604 (Mar. 12, 2012) (Arkansas); 77 Fed. Reg. 39,425 (July 3, 2012) (Louisiana); 77 Fed. Reg. 71,533 (Dec. 3, 2012) (Michigan); 78 Fed. Reg. 8,706 (Feb. 6, 2013) (Minnesota); 77 Fed. Reg. 57,864 (Sept. 18, 2012) (Montana); 77 Fed. Reg. 40,150 (July 6, 2012) (Nebraska); 77 Fed. Reg. 50,936 (Aug. 23, 2012) (Nevada); 76 Fed. Reg. 52,388 (Aug. 22, 2011) (New Mexico); 77 Fed. Reg. 20,894 (Apr. 6, 2012) (North Dakota); 76 Fed. Reg. 81,728 (Dec. 28, 2011) (Oklahoma); 77 Fed. Reg. 74,355 (Dec. 14, 2012) (Utah); 77 Fed. Reg. 33,022 (June 4, 2012) (Wyoming) (proposed). 7 Arizona v. EPA, No. 13-70366 (9th Cir., filed Jan. 31, 2013); Louisiana Dep’’t of Env. Quality v. EPA, No. 12-60672 (5th Cir., filed Sept. 4, 2012); Michigan v. EPA, No. 13-2130 (8th Cir., filed May 22, 2013); Cliffs Natural Res., Inc. v. EPA, No. 13-1758 (8th Cir., filed Apr. 4, 2013) (Michigan and Minnesota); PPL Montana, LLC v. EPA, No. 12-73757 (9th Cir., filed Nov. 16, 2012); Nebraska v. EPA, No. 12-3084 (8th Cir., filed Sept. 4, 2012); Martinez, et al. v. EPA, No. 11-9567 (10th Cir., filed Oct. 21, 2011) (New Mexico); North Dakota v. EPA, 730 F.3d 750 (8th Cir. 2013); Oklahoma v. EPA (the instant case); Utah v. EPA, No. 13-9535 (10th Cir., filed Mar. 21, 2013). 26 see North Dakota v. EPA, 730 F.3d 750, 761 (8th Cir. 2013), the ripple effect will magnify the harms caused by the Tenth Circuit’’s decision. Billion-dollar plan after billion-dollar plan will be forced on the States. And once construction begins in order to implement those plans, it cannot practically be unwound. Additionally, the decision not only harms Oklahoma now, it also limits the technical tools Oklahoma has available to it in developing future Regional Haze State Implementation Plans for the remaining forty-six years of the Regional Haze Program. Oklahoma’’s next State Implementation Plan is due in 2018, and the BART determinations made now——whether by Oklahoma or EPA——will directly affect the choices and decisions made by Oklahoma for the next half-a-century. EPA’’s imposition of a Federal Implementation Plan in this first planning period of the Regional Haze program unlawfully ties Oklahoma’’s hands as to what it can do in the future——a direct repudiation of Congress’’s mandate that the States lead the design and implementation of the Regional Haze Program. 2. Much like it did in Alaska Department, EPA here has yet again called into question numerous other statutes that embody the principle of cooperative federalism. See, e.g., New York v. United States, 505 U.S. 144, 167-168 (1992) (identifying ““numerous federal statutory schemes”” of this nature, including the Clean Water Act, 33 U.S.C. §§ 1251 et seq., the Occupational Safety and Health Act, 29 U.S.C. §§ 651 et seq., the Resource Conservation and Recovery Act, 42 U.S.C. §§ 6901 et seq., and the Alaska National Interest Lands Conservation Act, 16 U.S.C. §§ 3101 et seq.). Much like the Clean Air Act, these statutes are based on shared 27 federal-state responsibility, whereby the federal government sets standards and the States——if they opt to undertake the responsibility——are given broad flexibility in implementing those standards. Cooperative-federalism promotes federalism because ““state governments remain responsive to the local electorate’’s preferences; state officials remain accountable to the people.”” New York v. United States, 505 U.S. at 167-168. The Tenth Circuit’’s decision, by transferring from the State to EPA core discretionary authority under the leading cooperative-federalism statutory regimes, threatens to undermine the balance of power struck by Congress and accepted by the States when they assumed the responsibilities offered under the Act. For this reason too, the decision merits review. CONCLUSION For these reasons, the petition for a writ of certiorari should be granted, and the judgment below reversed. 28 Respectfully submitted, E. Scott Pruitt Oklahoma Attorney General Patrick R. Wyrick Solicitor General Counsel of Record P. Clayton Eubanks Deputy Solicitor General Oklahoma Attorney General’’s Office 313 NE 21st Street Oklahoma City, OK 73105 (405) 521-3921 fc.docket@oag.ok.gov scott.pruitt@oag.ok.gov patrick.wyrick@oag.ok.gov clayton.eubanks@oag.ok.gov Attorneys for Petitioner State of Oklahoma Michael Graves Thomas P. Schroedter HALL ESTILL, Attorneys at Law 320 South Boston Ave., Suite 200 Tulsa, OK 74103 (918) 594-0443 mgraves@hallestill.com tschroedter@hallestill.com Attorneys for Petitioner Oklahoma Industrial Consumers Energy 29 Brian J. Murray Charles T. Wehland Dennis Murashko JONES DAY 77 West Wacker Drive Chicago, IL 60601 (312) 782-3939 bjmurray@jonesday.com ctwehland@jonesday.com dmurashko@jonesday.com Michael L. Rice JONES DAY 717 Texas, Suite 3300 Houston, TX 77002 (832) 239-3640 mlrice@jonesday.com Attorneys for Petitioner Oklahoma Gas And Company Electric i APPENDIX TABLE OF CONTENTS Appendix A Denial of Petitions for Review of Final Decision Issued by the United States Environmental Protection Agency and Judgment in the United States Court of Appeals for the Tenth Circuit (July 19, 2013) . . . . . . . . . . . . . . . App. 1 Appendix B Final Rule, Environmental Protection Agency, 40 CFR Part 52 (December 28, 2011) . . . . . . . . . App. 56 Appendix C Order Denying Rehearing in the United States Court of Appeals for the Tenth Circuit (October 31, 2013) . . . . . . . . . . App. 209 Appendix D Statutes and Regulations . . . . App. 211 42 U.S.C.A. § 7491 . . . . . . . . . . App. 211 40 C.F.R. § 51.308 . . . . . . . . . . App. 218 Appendix E Excerpts from Regional Haze Implementation Plan Revision, State of Oklahoma, Department of Environmental Quality (February 2, 2010) . . . . . . . . . . App. 244 Appendix F Order in the United States Court of Appeals for the Tenth Circuit (June 22, 2012) . . . . . . . . . . . . . App. 246 App. 1 APPENDIX A PUBLISH UNITED STATES COURT OF APPEALS TENTH CIRCUIT [Filed July 19, 2013] No. 12-9526 _______________________________________ STATE OF OKLAHOMA; OKLAHOMA ) INDUSTRIAL ENERGY CONSUMERS, ) an unincorporated association, ) Petitioners, ) ) v. ) ) UNITED STATES ENVIRONMENTAL ) PROTECTION AGENCY, ) Respondent. ) --------------------------------------------------------- ) SIERRA CLUB, ) Intervenor-Respondent, ) ) and ) ) PACIFICORP; AMERICAN COALITION ) FOR CLEAN COAL ELECTRICITY; ) NATIONAL PARKS ) CONSERVATION ASSOCIATION, ) Amici Curiae. ) _______________________________________) App. 2 No. 12-9527 _______________________________________ OKLAHOMA GAS & ELECTRIC ) COMPANY, ) Petitioner, ) ) v. ) ) UNITED STATES ENVIRONMENTAL ) PROTECTION AGENCY, ) Respondent. ) --------------------------------------------------------- ) SIERRA CLUB, ) Intervenor-Respondent, ) ) and ) ) PACIFICORP; AMERICAN COALITION ) FOR CLEAN COAL ELECTRICITY; ) NATIONAL PARKS CONSERVATION ) ASSOCIATION, ) Amici Curiae. ) _______________________________________) PETITION FOR REVIEW OF FINAL DECISION ISSUED BY THE UNITED STATES ENVIRONMENTAL PROTECTION AGENCY EPA-R06-OAR-2010-0190 E. Scott Pruitt, Oklahoma Attorney General, (P. Clayton Eubanks, Assistant Attorney General; Michael Graves and Thomas P. Schroedter of Hall Estill, Tulsa, Oklahoma, with him on the briefs), Oklahoma City, Oklahoma, for Petitioners State of Oklahoma and Oklahoma Industrial Energy Consumers. App. 3 Brian J. Murray of Jones Day, Chicago, Illinois, (Thomas E. Fennell of Jones Day, Dallas, Texas; Michael L. Rice of Jones Day, Houston, Texas; Charles T. Wehland of Jones Day, Chicago, Illinois, on the briefs), for Petitioner Oklahoma City Gas & Electric Company. Stephanie J. Talbert, United States Department of Justice, Environment & Natural Resources Division, Environmental Defense Section, Washington, D.C. (Ignacia S. Moreno, Assistant Attorney General; M. Lea Anderson and Barbara Nann, Of Counsel, United States Environmental Protection Agency, with her on the brief), for Respondent. Andrea Issod, (Elena Saxonhouse and Sanjay Narayan with her on the brief), San Francisco, California, for the Intervenor, Sierra Club. Michael G. Jenkins, Assistant General Counsel, PacifiCorp Energy, Salt Lake City, Utah, and E. Blaine Rawson, Ray Quinney & Nebeker, P.C., Salt Lake City, Utah, filed an amicus curiae brief on behalf of PacifiCorp, Amicus Curiae. Paul M. Seby and Marian C. Larsen of Moye White LLP, Denver, Colorado, filed an amicus curiae brief on behalf of the American Coalition for Clean Coal Electricity, Amicus Curiae. Stephanie Kodish, Knoxville, Tennessee, filed an amicus curiae brief on behalf of the National Parks Conservation Association, Amicus Curiae. Before BRISCOE, Chief LUCERO, Circuit Judges. Judge, KELLY and App. 4 BRISCOE, Chief Judge. In these consolidated petitions for review, petitioners1 challenge a final rule promulgated by the United States Environmental Protection Agency under the Clean Air Act. The petitioners argue that the EPA impermissibly rejected Oklahoma’’s plan to limit the emissions of sulfur dioxide at Oklahoma Gas and Electric Company power plants and replaced it with its own more stringent regulations, which petitioners contend usurped the state’’s authority and will require sizable expenditures on unnecessary technology. We conclude that the EPA has authority to review the state’’s plan and that it lawfully exercised that authority in rejecting it and promulgating its own. Exercising our jurisdiction under 42 U.S.C. § 7607(b)(1), we deny the petitions for review. I A. Statutory Background The Clean Air Act ““uses a cooperative-federalism approach to regulate air quality.”” U.S. Magnesium, LLC v. EPA, 690 F.3d 1157, 1159 (10th Cir. 2012). Under the Clean Air Act (CAA), the Environmental Protection Agency (EPA) must create and review national ambient air quality standards for certain pollutants. See 42 U.S.C. §§ 7408, 7409. States then have the responsibility to adopt state implementation plans (SIPs), ““which provide[] for implementation, 1 The petitioners include the state of Oklahoma, the Oklahoma Industrial Energy Consumers interest group, and the Oklahoma Gas and Electric Company. App. 5 maintenance, and enforcement”” of those primary and secondary air quality standards. § 7410(a)(1). States, however, exercise this authority with federal oversight. The EPA reviews all SIPs to ensure that the plans comply with the statute. The EPA may not approve any plan that ““would interfere with any applicable requirement”” of this chapter of the United States Code. § 7410(l). The EPA has a duty to create its own federal implementation plan (FIP) if either: 1) it ““finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under subsection (k)(1)(A) of this section””; or 2) it ““disapproves a State implementation plan submission in whole or in part.”” § 7410(c)(1). The duty to promulgate a FIP exists ““unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such Federal implementation plan.”” Id. At issue in this case are the portions of the CAA that seek to protect visibility at certain national parks and wildlife areas. The CAA requires that the EPA promulgate regulations ““to assure . . . reasonable progress toward”” preventing any future and ““remedying . . . any existing, impairment of visibility in mandatory class I Federal areas which impairment results from manmade air pollution.”” § 7491(a)(1), (a)(4). It also requires that the EPA ensure that each state plan ““contain[s] such emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward meeting the national goal.”” § 7491(b)(2). App. 6 Relevant in this case are the CAA’’s mandates regarding sources that contribute to visibility impairments. SIPs must include: except as otherwise provided . . . a requirement that each major stationary source which is in existence on August 7, 1977, but which has not been in operation for more than fifteen years as of such date, and which, as determined by the State (or the Administrator in the case of a [FIP]) emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area, shall procure, install, and operate, as expeditiously as practicable (and maintain thereafter) the best available retrofit technology, as determined by the State (or the Administrator in the case of a [FIP]) for controlling emissions from such source for the purpose of eliminating or reducing any such impairment. § 7491(b)(2)(A). To simplify, a state——or the EPA, when promulgating a FIP——must: 1) determine which of the eligible major stationary sources in their state contributes to visibility impairment; and then 2) determine the ““best available retrofit technology”” for controlling the emissions causing that impairment at that source. Id. When determining ““best available retrofit technology”” (BART): the State (or the Administrator in determining emission limitations which reflect such technology) shall take into consideration [1] the costs of compliance, [2] the energy and nonair quality environmental impacts of compliance, App. 7 [3] any existing pollution control technology in use at the source, [4] the remaining useful life of the source, and [5] the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. § 7491(g)(2). The CAA requires that the EPA create guidelines for the states ““on appropriate techniques and methods for implementing this section.”” § 7491(b)(1). For ““a fossil-fuel fired generating powerplant having a total generating capacity in excess of 750 megawatts, the emission limitations required under this paragraph shall be determined pursuant”” to the regulations promulgated by the EPA. § 7491(b). The EPA has promulgated these BART guidelines at 40 C.F.R. § 51.308(e). B. Procedural Background In 2005, the EPA issued an updated version of its Regional Haze Rule that required states to submit SIP revisions by December 17, 2007. See Regional Haze Program Requirements, 40 C.F.R. § 51.308(b). On January 15, 2009, the EPA took final action in finding that Oklahoma——along with 31 other states, the District of Columbia, and the U.S. Virgin Islands——failed to submit a SIP that addressed any of the Regional Haze elements by this deadline. See Finding of Failure To Submit State Implementation Plans Required by the 1999 Regional Haze Rule, 74 Fed. Reg. 2392-01 (Jan. 15, 2009). This triggered the EPA’’s duty to promulgate a federal implementation plan within two years. See 42 U.S.C. § 7410(c)(1). App. 8 Before the EPA promulgated a FIP, however, Oklahoma submitted its SIP. See Oklahoma Regional Haze State Implementation Plan, Joint Appendix (JA) at 55 (Feb. 17, 2010). At issue in this petition are the SIP’’s BART determinations with respect to two units at Oklahoma Gas & Electricity’’s (OG&E’’s) Muskogee Generating Station and two units at its Sooner Generating Station. The Oklahoma SIP set a sulfur dioxide (SO2) emissions limits of 0.65 lb/mmBtu (thirty-day average) and 0.55 lb/mmBtu (annual average) for each of these four units. See OG&E Muskogee Generating Station BART Review, JA at 187 (Jan. 15, 2010); OG&E Sooner Generating Station BART Review, JA at 221 (Jan. 15, 2010). The BART for each of these units included OG&E’’s continued use of low-sulfur coal. The SIP considered, but rejected, an emissions limit that would require the installation of so-called scrubbers to remove SO2. See Muskogee BART Review, JA at 213; Sooner BART Review, JA at 247. ““The cost for [dry scrubbers] is too high, the benefit too low and these costs, if borne, further extend the life expectancy of coal as the primary fuel in the Sooner [and Muskogee] facilit[ies] for at least 20 years and beyond,”” according to OG&E’’s BART analyses. See id. On March 22, 2011, the EPA proposed a rule that would partially approve and partially disapprove Oklahoma’’s SIP. Proposed Rule, 76 Fed. Reg. 16,168-01, 16,169 (Mar. 22, 2011). The SO2 emission limitations for OG&E’’s four units were among the parts of the SIP that the EPA proposed disapproving. The EPA said that Oklahoma failed to follow the promulgated regulations in determining BART. Id. at 16,182. Specifically, the EPA said that Oklahoma ““did App. 9 not properly ‘‘take into consideration the costs of compliance’’ when it relied on cost estimates that greatly overestimated the costs of dry and wet scrubbing to conclude these controls were not cost effective.”” Id. (quoting 40 C.F.R. § 51.308(e)(1)(ii)(A)). ““Given that scrubbers are typically considered to be highly cost-effective controls for power plants such as those at issue, [the EPA] retained a consultant to independently assess the suitability and costs of installing these controls.”” Id. The EPA found the scrubbers to be substantially more cost effective than Oklahoma did. Id. at 16,183. For example, Oklahoma estimated the cost of the scrubbers to be $7,147 per ton of SO2 removed at one of the Sooner Generating Station units. Id. The EPA projected scrubbers at that same unit would cost $1,291 per ton of SO2 removed. Id. In addition to proposing the partial disapproval of the SIP, the EPA proposed creating its own federal implementation plan in the same action. Id. at 16,168. The EPA proposed an SO2 emissions limit of 0.06 lb/mmBtu (thirty-day average). Id. at 16,193-94. Based on this limit, the EPA believed the use of dry scrubbers would be cost effective. Id. at 16,183. After notice and comment, the EPA published the final rule enacting these emissions limits. See Final Rule, 76 Fed. Reg. 81,728-01 (Dec. 28, 2011). On February 24, 2012, the state of Oklahoma and the Oklahoma Industrial Energy Consumers filed in this court a petition seeking review of the final rule (Case No. 12-9526). OG&E filed its petition for review the same day (Case No. 12-9527). We later issued an order granting a motion to consolidate these petitions. App. 10 The petitioners also took steps to stay the application of the rule. The same day they filed petitions for review, the petitioners filed with the EPA a motion for reconsideration and a request for an administrative stay.2 The petitioners also filed a motion in this court seeking a stay pending a hearing on the merits. A two-judge panel of this court granted the petitioners’’ motion to stay the portion of the rule requiring the reduction of SO2 emissions at these four OG&E units. Oklahoma v. EPA, Nos. 12-9526 and 12-9527, at 1-2 (10th Cir. June 22, 2012). Meanwhile, appellate briefing progressed. The petitioners raise a number of objections to the final rule, arguing that the EPA has usurped the state’’s authority in an effort to force OG&E to spend more than one-billion dollars to install unnecessary technology in the next five years. First, they argue that the EPA exceeded its statutory authority by disapproving Oklahoma’’s BART determination. 2 Under the CAA, the filing of a petition for reconsideration does not affect the finality of an EPA action for the purposes of judicial review. See 42 U.S.C. § 7607(b)(1) (““The filing of a petition for reconsideration by the Administrator of any otherwise final rule or action shall not affect the finality of such rule or action for purposes of judicial review nor extend the time within which a petition for judicial review of such rule or action under this section may be filed, and shall not postpone the effectiveness of such rule or action.””); see also Natural Res. Def. Council v. Abraham, 355 F.3d 179, 203 n.11 (2d Cir. 2004). While the Third Circuit has held that a pending petition for reconsideration deprived it of jurisdiction under the CAA, see W. Penn Power Co. v. EPA, 860 F.2d 581, 587-88 (3d Cir. 1988), it reached this result before the CAA was amended to prevent petitions for reconsideration from affecting finality. Clean Air Act, Amendments, Pub. L. No. 101-549, § 706, 104 Stat. 2399 (1990). App. 11 Second, they argue that, even if the EPA had this authority, the EPA acted arbitrarily and capriciously by disapproving Oklahoma’’s SIP. Third, they argue that the EPA acted arbitrarily and capriciously in promulgating its FIP. Fourth, the petitioners argue that the EPA failed to provide them adequate notice of aspects of the final rule. Finally, the petitioners argue the EPA violated the CAA by promulgating the FIP in the same action in which it partially disapproved of the SIP and after the two-year deadline to promulgate a FIP had expired. II The petitioners argue that the EPA exceeded its statutory authority by rejecting Oklahoma’’s BART determinations and replacing them with its own. The petitioners say that the EPA’’s action tramples on the discretion that Congress afforded states to make these decisions. The CAA’’s cooperative-federalism policy supports this view, the petitioners say. More specifically, the petitioners point to the statute’’s legislative history and its language——mandating BART ““as determined by the State.”” In the petitioners’’ view, this all indicates that the statute unambiguously prescribes a limited role for the EPA as regards BART determinations. In interpreting the CAA, we must follow the guidance set forth in Chevron, U.S.A., Inc. v. Natural Res. Def. Council, Inc., 467 U.S. 837 (1984). ““If the statute is clear, we apply its plain meaning and the inquiry ends.”” Ariz. Pub. Serv. Co. v. EPA, 562 F.3d 1116, 1123 (10th Cir. 2009) (quotation omitted). ““If the statute is silent or ambiguous about the question at issue . . . we defer to the authorized agency and apply App. 12 the agency’’s construction so long as it is a reasonable interpretation of the statute.”” Id. (quotation omitted). ““[A]dministrative implementation of a particular statutory provision qualifies for Chevron deference when it appears that Congress delegated authority to the agency generally to make rules carrying the force of law, and that the agency interpretation claiming deference was promulgated in the exercise of that authority.”” United States v. Mead Corp., 533 U.S. 218, 226-27 (2001). We agree with the EPA that the statute provides the agency with the power to review Oklahoma’’s BART determination for these four units. The EPA may not approve any plan revision ““if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress . . . or any other applicable requirement of this chapter.”” 42 U.S.C. § 7410( l). And under § 7410(a)(2)(J) SIPs must ““meet the applicable requirements of . . . part C of this subchapter””——which includes the provisions of the CAA related to visibility. See §§ 7491, 7492. The visibility statute itself requires the EPA to promulgate regulations that ““require each applicable implementation plan . . . to contain such emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward meeting the national goal.”” § 7491(b)(2). That includes a requirement that the state make BART determinations. And while it is undoubtedly true that the statute gives states discretion in balancing the five BART factors, it also mandates that the state adhere to certain requirements when conducting a BART analysis. The state plan must include a BART App. 13 determination for any eligible plant that ““may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area.”” § 7491(b)(2). In addition, § 7491(b) requires that the BART determination for units at power plants like those at issue here——having a total generating capacity of greater than 750 megawatts——““shall be determined pursuant”” to the EPA regulations. See 42 U.S.C. § 7491(b) (““In the case of a fossil-fuel fired generating powerplant having a total generating capacity in excess of 750 megawatts, the emission limitations required under this paragraph shall be determined pursuant to guidelines, promulgated by the Administrator under paragraph (1).””); see also EPA Br. at 7. As required by the statute, the EPA has promulgated regulations providing guidelines for making BART determinations. Like the statute, the regulations require that BART determinations at large power plants follow these guidelines. 40 C.F.R. § 51.308(e)(1)(ii)(B) (““The determination of BART for fossil-fuel fired power plants having a total generating capacity greater than 750 megawatts must be made pursuant to the guidelines appendix Y of this part (Guidelines for BART Determinations Under the Regional Haze Rule).””). The EPA rejected Oklahoma’’s SIP because the BART determinations failed to comply with these guidelines. See EPA Br. at 22 (““Specifically, EPA concluded that Oklahoma failed to reasonably consider the ‘‘cost of compliance’’ factor by calculating costs as required by the BART guidelines, which led to an ‘‘unreasoned and unjustified’’ BART determination.””). Given that the statute mandates that the EPA must ensure SIPs comply with the statute, we fail to see how the EPA would be without the authority to review App. 14 BART determinations for compliance with the guidelines. The D.C. Circuit’’s opinion in American Corn Growers Ass’’n v. EPA, 291 F.3d 1 (D.C. Cir. 2002), does not alter this conclusion. At issue in Corn Growers was a provision of the Regional Haze Rule that required states to make BART decisions based in part on the geographical location of a source, as opposed to its actual emissions. Id. at 4-5. The rule required BART-eligible sources be subject to BART ““even absent empirical evidence of that source’’s individual contribution to visibility impairment in a Class I area so long as the source is located within a region that may contribute to visibility impairment.”” Id. at 5. When making the BART determination, the state needed to ““analyze the degree of visibility improvement that would be achieved . . . as a result of the emission reductions achievable from all sources subject to BART located within the region that contributes to visibility impairment.”” Id. at 6 (quotation and emphasis omitted). The D.C. Circuit held the EPA’’s approach was ““inconsistent”” with the CAA. Id. at 7-8. The D.C. Circuit cited two ways in which the rule was inconsistent with the statute. First, the EPA’’s approach ““distort[ed] the judgment Congress directed the states to make for each BART-eligible source”” by treating one of the five BART factors differently than the others. Id. at 6. The rule, for instance, prevented a state from ““consider[ing] the degree to which new equipment at a particular source would help cure the haze in some distant national park.”” Id. at 7. ““Under EPA’’s take on the statute, it is therefore entirely possible that a source may be forced to spend millions App. 15 of dollars for new technology that will have no appreciable effect on the haze in any Class I area.”” Id. Second, the D.C. Circuit said that the rule impermissibly ““constrain[ed] authority Congress conferred on the states.”” Id. at 9. The court said that the statute and the legislative history suggested that the states had broad authority to weigh the statutory factors and make BART determinations. Id. at 8. The D.C. Circuit noted that the Conference Report on the 1977 amendments to the CAA specifically referenced ““an agreement to reject the House bill’’s provisions giving EPA the power to determine whether a source contributes to visibility impairment and, if so, what BART controls should be applied to that source.”” Id. The agreement instead added the language delegating this authority to the state. Id. ““The Conference Report thus confirms that Congress intended the states to decide which sources impair visibility and what BART controls should apply to those sources.”” Id. The Haze Rule, though, ““ties the states’’ hands and forces them to require BART controls at sources without any empirical evidence of the particular source’’s contribution to visibility impairment in a Class I area.”” Id. Here, though, the statute and the legislative history support our conclusion that the EPA may reject BART determinations that do not comply with the guidelines. True, the modification of the original House bill reflects an intent to shift the power to determine BART from the EPA to the states. But, as above, it still placed statutory limits on those state decisions. While the legislative history may evidence an intent to prevent the EPA from directly making those BART decisions, it App. 16 does not necessarily evidence an intent to deprive the EPA of any authority to ensure that these BART decisions comply with the statute. In the present case, the EPA did not reject the petitioners’’ BART determination because it disagreed with the way it balanced the five factors. It rejected the BART determination because it failed to follow the guidelines——as required by the statute——in calculating one of those factors. All the conference agreement referenced by the D.C. Circuit did was shift the initial responsibility for making BART determinations from the EPA to the state. But that does not differ from other parts of the CAA——states have the ability to create SIPs, but they are subject to EPA review. In addition, the Conference Report emphasized that the BART determinations for large power plants must comply with EPA guidelines: The agreement clarifies that the State, rather than the Administrator, identifies the source that impairs visibility in the Federal class I areas identified and thereby fall within the requirements of this section. .... In establishing emission limitations for any source which impairs visibility, the State shall determine what constitutes ‘‘best available retrofit technology’’ (as defined in this section) in establishing emission limitations on a sourceby-source basis to be included in the State implementation plan so as to carry out the requirements of this section. The regulations and Federal guidelines required by the House passed bill for determining this technology are App. 17 eliminated for all sources other than fossil fuel electric generating plants with a total generating capacity in excess of 750 megawatts. H.R. Rep. No. 95-564, at 155 (1977) (Conf. Rep.) (emphasis added). The Senate discussion about the Conference Report also highlighted the role that the guidelines play in BART determinations for large power plants: [Senator] McClure. And while those existing sources are limited to the 28 major sources contained in the Senate bill’’s definition of major emitting facilities, exempting any such source which has the maximum potential to emit less than 250 tons per year, Federal guidelines apply only to fossil-fuel fired generating plants in excess of 750 megawatts? [Senator] Muskie. That is correct. [Senator] McClure. Under the conference agreement, does the State retain sole authority for identification of sources for the purpose of visibility issues under this section? [Senator] Muskie. Yes; the State, not the Administrator, identifies a source that may impair visibility and thereby falls within the requirement of section 128. [Senator] McClure. And does this also hold true for determination of ““Best Available Retrofit Technology””? [Senator] Muskie. Yes; here again it is the State which determines what constitutes ““Best App. 18 Available Retrofit Technology,”” as defined in section 128. The Federal guidelines apply only to the large powerplants we have described. 123 Cong. Rec. S26,854 (daily ed. Aug. 4, 1977) (emphasis added). The last sentence——omitted by petitioners in their brief——makes clear that the statute requires that the BART determination here comply with the guidelines. See Pet. Opening Br. at 15. And because the EPA monitors SIPs for compliance with the statute, it must monitor BART determinations for compliance with the guidelines. To be sure, the guidelines themselves might somehow conflict with the statute. But the petitioners have not argued that any conflict exists here.3 We therefore hold that the EPA 3 In its amicus brief, the American Coalition for Clean Coal Electricity asserts that some conflict between the guidelines and statute may exist because: EPA can provide the States with guidelines only ““on appropriate techniques and methods,”” including ““(A) methods for identifying, characterizing, determining, quantifying, and measuring visibility impairment in Federal areas referred to in paragraph (1), (B) modeling techniques (or other methods) for determining the extent to which manmade air pollution may reasonably be anticipated to cause or contribute to such impairment, and methods for preventing and remedying such manmade air pollution and resulting visibility impairment.”” See cross-reference from [42 U.S.C. § 7491(b)] (last paragraph) to [§ 7941(b)(1) to § 7491(a)(3)]. Thus, EPA’’s role is to provide procedural and technical guidance to the States in making BART determinations. See Am. Coalition for Clean Coal’’s Br. at 12 (emphasis added). However, the statute does not limit the guidelines so restrictively. First, the guidelines must be made as part of regulations that App. 19 had the authority to review Oklahoma’’s BART determination with respect to these two power plants. III Having held that the EPA possesses the authority to review these BART decisions, we must now determine whether the EPA lawfully exercised that authority when it rejected Oklahoma’’s SIP. Petitioners argue that the EPA took arbitrary and capricious action in rejecting two sets of cost estimates they used in determining BART. The EPA, on the other hand, argues that it properly rejected these estimates——and, thus, the SIP that relied on them——for failure to comply with its guidelines. We follow the standards of the Administrative Procedure Act (APA) in reviewing the EPA’’s actions under the CAA. See Magnesium, 690 F.3d at 1164. Under the APA, we must hold unlawful any agency action that is ““arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.”” 5 U.S.C. § 706(2). ““Under the arbitrary or capricious standard, we must determine whether the agency considered the relevant data and rationally explained ensure ““reasonable progress toward meeting the national goals”” specified in the statute. § 7491(a)(4), (b)(1). Second, those guidelines must merely ““tak[e] into account”” recommendations from a report to Congress on the methods and techniques referenced in the statute, 42 U.S.C. § 7491(b)(1), which includes ““methods for preventing and remedying such manmade air pollution and resulting visibility impairment.”” 42 U.S.C. § 7491(a)(3)(C). Moreover, the amicus brief fails to explain why the EPA could provide these regulations providing procedural and technical guidance, but yet lacks the authority to ensure states complied with them. App. 20 its decision.”” Ariz. Pub. Serv. Co., 562 F.3d at 1122. ““Agency action is arbitrary or capricious if the agency has relied on factors which Congress has not intended it to consider, entirely failed to consider an important aspect of the problem, offered an explanation for its decision that runs counter to the evidence before the agency, or is so implausible that it could not be ascribed to a difference in view or the product of agency expertise.”” Id. at 1123. (quotation omitted). ““Even when an agency explains its decision with less than ideal clarity, a reviewing court will not upset the decision on that account if the agency’’s path may reasonably be discerned.”” Alaska Dep’’t of Envtl. Conservation, 540 U.S. at 497 (quotation omitted). In addition, we note that ““[w]hen an agency interprets its own regulation, the Court, as a general rule, defers to it unless that interpretation is plainly erroneous or inconsistent with the regulation.”” Decker v. Nw. Envtl. Def. Ctr., 133 S. Ct. 1326, 1337 (2013) (quotation omitted). A. 2008 Cost Estimates The petitioners argue that the EPA arbitrarily rejected a set of cost estimates that OG&E submitted to the EPA in 2008 (2008 Cost Estimates). The petitioners claim that the ““EPA acknowledged that ‘‘OG&E did utilize the ““EPA Air Pollution Control Cost Manual”” when constructing its [May 2008] cost estimates.’’”” Pet. Opening Br. at 20 (quoting EPA Region 6 Comments on ODEQ’’s BART Engineering Analyses, JA at 1132 (Nov. 4, 2008)). The 2008 Cost Estimates were ““more than ten times EPA’’s stated average costs per ton for this technology, and nearly five times as much as the upper limit of EPA’’s expected cost range.”” Id. at 21. The EPA should have addressed App. 21 these numbers, petitioners say, because they prove the scrubbers were not cost effective. This argument is without merit. The EPA never stated that the 2008 Cost Estimates complied with the Control Cost Manual.4 In context, the EPA simply acknowledged that OG&E purported to have used the manual in constructing these estimates. Indeed, it requested that OG&E note any deviations from the cost manual——as required by the guidelines5——after pointing out that OG&E’’s estimates ““seem[ed] high compared to what EPA has seen in other BART analysis.”” EPA 4 The entire EPA comment included the following: Regarding its cost estimates, OG&E’’s estimates seem high compared to what EPA has seen in other BART analyses. OG&E cites increased equipment costs, in part due to the ““sellers market”” that resulted from the CAIR program. Since the CAIR has been vacated, OG&E should solicit revised bids from pollution control equipment vendors. Region 6 is aware of similarly sized and configured facilities that estimate much lower costs for the installation of wet or dry FGD systems. Region 6 notes that OG&E did utilize the ““EPA Air Pollution Control Cost Manual”” when constructing its cost estimates. However, OG&E should also note any areas in which where it has deviated from that guidance. EPA Region 6 Comments, JA at 1132 (emphases added). 5 The guidelines state that ““cost estimates should be based on the OAQPS Control Cost Manual, where possible.”” 40 C.F.R. pt. 51 app. Y(IV)(D)(4)(a). However, it also instructs that parties ““should include documentation for any additional information regarding purchased equipment costs, equipment life, replacement of major components, and any other element of the calculation that differs from the Control Cost Manual.”” 40 C.F.R. pt. 51 app. Y(IV)(D)(4)(a) n.15. App. 22 Region 6 Comments, JA at 1132; see also 40 C.F.R. pt. 51 app. Y(IV)(D)(4)(a) n.15.6 And in any event, the EPA did not ““ignore[]”” the 2008 Cost Estimates. Rather, the EPA explained that ““[t]hese 2008 costs are not valid under the overnight costing method”” required by the manual. Response to Technical Comments, JA at 1236. The 2008 Cost Estimates ““contain[ed] . . . fundamental methodological flaws, such as including escalation and Allowance for Funds Used During Construction (AFUDC).”” Id. ““The cost of scrubbers would not be substantially higher than those reported for other similar projects if OG&E had used the costing method and basis, i.e., overnight costs in current dollars, prescribed by the Control Cost 6 Petitioners argue in their reply brief that the EPA did not explicitly raise this response in its comments and therefore cannot use this reasoning to justify its decision on appellate review. Pet. Reply Br. at 10 n.1 (quoting Motor Vehicles Mfrs. Ass’’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 50 (1983) (““[A]n agency’’s action must be upheld, if at all, on the basis articulated by the agency itself.””)). But an agency ““need not address every comment, [although] it must respond in a reasoned manner to those that raise significant problems.”” Covad Commc’’ns Co. v. FCC, 450 F.3d 528, 550 (D.C. Cir. 2006) (quotation omitted). ““The failure to respond to comments is significant only insofar as it demonstrates that the agency’’s decision was not based on a consideration of the relevant factors.”” Id. (citations and quotation omitted). ““In making the ‘‘keystone’’ inquiry whether the [agency] engaged in reasoned decisionmaking, the reviewing court is to consider the larger administrative record.”” Mt. Diablo Hosp. v. Shalala, 3 F.3d 1226, 1234 (9th Cir. 1993) (quotation omitted). Here, the letter itself——which is part of the record——quite clearly explains the EPA’’s concerns about the 2008 Cost Estimates. And the petitioners did, in fact, submit new cost estimates. App. 23 Manual,”” the EPA said. Id. The EPA therefore had a reasonable basis for rejecting the 2008 Cost Estimates as not complying with the guidelines. B. The 2009 Cost Estimates The petitioners also argue that the EPA acted arbitrarily in rejecting the cost estimates submitted in 2009 (2009 Cost Estimates). These cost estimates included more site-specific data than the ones OG&E initially submitted. The petitioners say that the EPA should defer to Oklahoma’’s determination that the ““site-specific cost information submitted by OG&E in 2009 was credible, detailed, and specific for the individual facilities, going well beyond the default methodology recommended by the EPA guidance.”” Pet. Opening Br. at 23 (quotation omitted). This argument appears to be premised, in part, on our accepting the representation that the EPA conceded the 2008 Cost Estimates complied with the guidelines. The petitioners argue in their reply brief that for ““EPA to acknowledge receipt of cost estimates that it agreed were in compliance with the CCM, ask for site-specific cost estimates that go beyond the CCM, and then reject those site-specific estimates for not conforming to the CCM exemplifies arbitrary and capricious resultsoriented decisionmaking.”” Pet. Reply Br. at 11. We disagree with the petitioners’’ characterization of the EPA’’s actions. The EPA did not reject the mere use of any site-specific costs as not complying with the guidelines. It rejected this particular use of site-specific numbers because it ““recognized that how OG&E specified those vendor quotes and [its] subsequent use of them in its cost analysis was flawed.”” Response to Technical Comments, JA at 1308. The guidelines App. 24 require that states provide support for any site-specific costs that depart from the generic numbers in the Control Cost Manual. See 40 C.F.R. pt. 51 app. Y(IV)(D)(4)(a) n.15 (““You should include documentation for any additional information you used for the cost calculations, including any information supplied by vendors that affects your assumptions regarding purchased equipment costs, equipment life, replacement of major components, and any other element of the calculation that differs from the Control Cost Manual.””). OG&E never delivered to the EPA these detailed vendor estimates, preventing the EPA from conducting an adequate review to ensure these departures from the manual——and Oklahoma’’s approval of them——were justified. See 76 Fed. Reg. at 81,745 (““[M]uch of the documentation OG&E and others cite to support deviations from the Control Cost Manual was not provided to us. Thus, we were unable to analyze their contents and determine whether these deviations were appropriate.””); see, e.g., Response to Technical Comments, JA at 1239 (““For instance, although OG&E provided two spreadsheets that listed their cost line items, these spreadsheets, each over 600 lines in length (and including line items such as seeding and fertilizing the grass at the plant sites), were stripped of all cell calculations, preventing any meaningful review.””). And, as we discuss below in evaluating the EPA’’s action in promulgating its FIP, many of OG&E’’s costing assumptions were unjustified.7 7 We recognize that the EPA has less discretion when it takes actions to reject a SIP than it does when it promulgates a FIP. However, we believe that the EPA had reason to make the App. 25 Moreover, the EPA’’s consultant noted that, even if the departures from the generic numbers had been properly documented, the resulting costs were not analyzed in compliance with the manual. See Revised BART Cost-Effectiveness Analysis, JA at 1517 (October 2010) (““[I]t is possible to follow the generic costing method in the Cost Manual, relying on vendor quotes and other information to estimate scrubber capital and O&M costs. [OG&E’’s consultants] used vendor estimates for equipment costs but did not follow the generic costing method.””). The guidelines say that states should follow the manual’’s methodology so that projects can be more easily compared. The EPA said that OG&E should have used the ““overnight”” costing methodology. Instead, ““OG&E and others incorrectly assume that BART cost effectiveness should be based on the ‘‘all-in’’ cost method, which includes all of the costs of a financial transaction, including interest, commissions, and any other fees from a financial transaction up to the date that the project goes into operation, as of the assumed commercial operating dates of the scrubbers, 2014 and 2015.”” 76 Fed. Reg. at 81,744. For their part, the petitioners argue generally that the Control Cost Manual does not require the use of the ““overnight”” method used by the EPA. However, they do not point to any specific parts of the guidelines or the Control Cost Manual that contradict the EPA’’s approach. Instead, the petitioners argue that the EPA adjustments described in Section IV, Part B, even under the higher standard we would apply when evaluating its actions in rejecting a SIP. OG&E has yet to provide any justification for providing estimates that departed from the guidelines. App. 26 itself conceded that its methodology excluded only inflation. Pet. Opening Br. at 31. (““EPA claimed that the CCM required compliance with a ‘‘constant dollar’’ approach . . . . The constant dollar approach allows comparability in the BART context by removing the effects of inflation from cost estimates.””). Petitioners believe this means that it properly included the other costs, such as the Allowance for Funds Used During Construction, in its analyses. Unlike the petitioners, we do not read the EPA’’s statement as proof that the EPA believed the constant-dollar method requires removing only inflation. The EPA’’s consultant referenced the manual’’s adherence to the ““constant-dollar”” method as the reason for excluding inflation in the estimates. See Revised BART Cost-Effectiveness Analysis, JA at 1517 (““The cost metric estimated in the Manual is real or constant-dollar costs in that the effect of inflation has been removed.””). But the consultant never said that the Control Cost Manual excluded only inflation. In fact, the consultant explained throughout her report that the Control Cost Manual also required excluding many of the other costs on which OG&E had relied. See JA at 1519 (““Cost items such as escalation of costs, bond cost, and AFUDC are not part of the Cost Manual methodology for estimating costs.””); see, e.g., JA at 1520 (““[Allowance for Funds Used During Construction] are not part of the constant dollar approach found in the EPA Control Cost Manual and should not be included in the BART cost-effectiveness analysis.””). Viewing these comments as a whole, we do not believe the EPA or its consultant ever conceded inflation was the only cost that needed to be eliminated from OG&E’’s estimates. App. 27 The petitioners also refer to two affidavits from their experts that detail what they believe is the proper costing methodology. Even if we permitted these arguments to be incorporated by reference, we cannot consider these affidavits because they are outside of the administrative record. 42 U.S.C. § 7607(d)(7)(A). Aware of this hurdle, petitioners criticize the EPA’’s procedure, arguing that they had no opportunity to object to the EPA’’s use of the so-called ““overnight”” costing method because the EPA used it for the first time in the final rule. To be sure, the EPA used the term ““overnight”” method for the first time in the final rule. However, the EPA excluded the same costs in the final rule that it did throughout the entire process——the ““overnight”” method was simply the shorthand it used in the Final Rule to describe the exclusion of these costs. In fact, the petitioners’’ own comments to the EPA belie the argument they have made to us, since they challenged the exclusion of these costs in the administrative proceeding. See, e.g., Ex. B to OG&E’’s Comments: May 2011 BART Cost Analysis Report, JA at 1156 (May 20, 2011) (““EPA’’s consultant incorrectly argues that an AFUDC is not part of the constant dollar approach found in the EPA Control Cost Manual and should not be included in the BART cost-effectiveness analyses.”” (quotation omitted)). We see no reason to excuse petitioners’’ failure to raise these substantive arguments in their brief. Additionally, we do not have jurisdiction to consider any procedural error that might have occurred as a result of the EPA allegedly using the ““overnight”” method for the first time in the Final Rule. Under the CAA, ““[o]nly an objection to a rule or procedure which App. 28 was raised with reasonable specificity during the period for public comment . . . may be raised during judicial review.”” 42 U.S.C. § 7607(d)(7)(B). The fact that the petitioners could not have raised their objection about the use of the ““overnight”” method until after the final rule was published does not excuse them from the requirement they first raise the issue with the EPA. ““Rather, the CAA requires a petitioner to first raise its objection to the agency th[r]ough a petition for reconsideration.”” Appalachian Power Co. v. EPA, 249 F.3d 1032, 1065 (D.C. Cir. 2001). Petitioners here, though, filed their petition for reconsideration the same day they filed this petition for review. We therefore lack jurisdiction to rule on this procedural objection. See 42 U.S.C. § 7607(d)(7)(B) (““If the Administrator refuses to convene [a reconsideration proceeding], such person may seek review of such refusal in the United States court of appeals for the appropriate circuit . . . .””) (emphasis added). IV Petitioners also challenge decisions made by the EPA in promulgating the FIP. First, the petitioners argue that the EPA itself failed to follow the guidelines because it did not base its cost-effectiveness analysis on the historical emissions baseline. Second, petitioners argue that the EPA based its analysis on incorrect technological assumptions about the size of the scrubber that needs to be built. Third, the petitioners criticize many of the adjustments the EPA made to its cost estimates. Finally, the petitioners assert that ““[s]crubbers at the OG&E units would not have a significant impact on visibility.”” Id. at 36. We review these challenges under the same arbitrary and App. 29 capricious standard we used to evaluate the EPA’’s rejection of the SIP. However, we do so while recognizing this requires a slightly different perspective: evaluating the EPA’’s own choices under the guidelines, as opposed to evaluating its choice to reject the Oklahoma SIP under the guidelines. A. Baseline Emissions/Technical Feasibility Petitioners argue the EPA acted arbitrarily when it promulgated its FIP because it ignored the units’’ past rates of SO2 emissions in conducting its analysis. Under the guidelines, ““[a]verage cost effectiveness means the total annualized costs of control divided by annual emissions reductions (the difference between baseline annual emissions and the estimate of emissions after controls).”” 40 C.F.R. pt. 51 app. Y(IV)(D)(4)(c). ““The baseline emissions rate should represent a realistic depiction of anticipated annual emissions for the source.”” Id. at Y(IV)(D)(4)(d). ““In general, for the existing sources subject to BART, you will estimate the anticipated annual emissions based upon actual emissions from a baseline period.”” Id. ““When you project that future operating parameters (e.g., limited hours of operation or capacity utilization, type of fuel, raw materials or product mix or type) will differ from past practice, and if this projection has a deciding effect in the BART determination, then you must make these parameters or assumptions into enforceable limitations.”” Id. OG&E has been voluntarily using low-sulfur coal at these power plants. It therefore estimated that scrubbers would remove around 14,000 tons of SO2 per year at each of the power plants. Comments of OG&E on Proposed EPA Rule, JA at 1106. The EPA, however, App. 30 assumed that OG&E would begin to use high-sulfur coal if it installed the proposed scrubbers. The EPA, therefore, estimated that scrubbers would remove 43,428 tons of SO2 per year at one of the power plants, and 46,458 tons of SO2 per year at the other. Id. By assuming OG&E would remove larger amounts of SO2, while using cheaper, high-sulfur coal, the resulting conclusion was that the scrubbers appeared more cost effective. This links with petitioners’’ second objection: that the EPA impermissibly based its analysis on the construction of smaller, less expensive——but allegedly technically infeasible——scrubbers. Petitioners claim that EPA wrongly assumed that OG&E had the option of building a smaller scrubber based on the sulfur content of the coal it would burn. Scrubber size does not depend on the sulfur content of coal, the petitioners say. Rather, scrubber size must ““reflect the maximum potential heat input from the facility, and that number is essentially the same whether a facility burns high or low sulfur coal.”” Pet. Opening Br. at 28. A smaller scrubber would be impossible to build, or would significantly diminish the units’’ electricity production, petitioners say. The EPA says it made its calculations in response to the flawed assumptions made by the petitioners. In the EPA’’s view, the petitioners’’ analysis assumed that they would be building a much more powerful——and, more important, costly——scrubber system than was actually needed. The petitioners still assumed, though, that they would use low-sulfur coal in the future, making the scrubbers seem less cost effective than they actually would be, the EPA said. App. 31 The EPA’’s consultant, Dr. Phyllis Fox, analyzed two options to account for these alleged flaws in OG&E’’s analysis. In Option 1, Fox evaluated the cost effectiveness of the high powered scrubbers using an ahistorical baseline. Revised BART Cost-Effectiveness Analysis, JA at 1513. That is, the analysis assumed that OG&E——while currently using low-sulfur coal——would begin using cheaper, higher sulfur coal if it actually built these larger scrubbers. Id. at 1280. This increased the scrubbers’’ cost effectiveness because it anticipated the removal of greater amounts of SO2. Id. at 1513-14. In Option 2, the EPA evaluated the cost effectiveness of a lower powered scrubber using the historical baseline emissions. Id. at 1514. In order to design this less powerful scrubber, the EPA used a model that OG&E’’s consultants had created for the EPA in a different action.8 JA at 1283. This option increased the cost effectiveness of the scrubbers—— assuming the continued use of low-sulfur coal——because it assumed the scrubbers would be less expensive. The evaluation of the petitioners’’ argument essentially hinges on the technical feasibility of a smaller unit. We agree with the petitioners that the guidelines typically require the use of the historical emissions baseline. And we agree that if the EPA were to, without justification, increase the historical emissions baseline, it would encourage the use of 8 The EPA used this model in the final rule. The EPA’’s consultant had used a less precise model for basic engineering in the proposal, which the EPA conceded was an ““oversimplification.”” Response to Technical Comments, JA at 1283. App. 32 high-sulfur coal simply for the purpose of removing greater amounts of SO2. But what is framed as an argument over the baseline is really an argument over the size of the proposed scrubbers. The cost effectiveness of scrubbers would routinely be understated if proposals included costing for scrubbers much larger than needed. ““While it may be prudent to overdesign for many reasons, the cost of overdesign should not be attributed to BART, especially when the emission reductions do not consider the overdesign,”” the EPA said. Response to Technical Comments. Id. at 1283. If OG&E wanted larger scrubbers, then the EPA needed some way to isolate the BART-related costs from the non-BARTrelated costs. The EPA took this into account by adjusting the baseline emissions under the assumption that, if OG&E built the scrubbers it proposed, it would presumably shift to using cheaper forms of coal. Left to evaluate the arguments of the parties’’ experts, we must give deference to the EPA. See San Juan Citizens Alliance v. Stiles, 654 F.3d 1038, 1045 (10th Cir. 2011) (““The deference we give agency action is especially strong where the challenged decisions involve technical or scientific matters within the agency’’s area of expertise.”” (quotation omitted)).9 While 9 The petitioners argue that we should not afford the EPA deference because the EPA’’s consultant did not speak to OG&E directly and did not visit the site. Pet. Br. at 19 n.9. They cite no authority for this proposition. Further, the EPA said in its final rule that it ““met with OG&E and its consultant concerning the development of our proposal and had extensive communications clarifying particular technical points,”” which it conveyed to its consultant to incorporate in her report. 76 Fed. Reg. at 81,728. App. 33 the petitioners criticize some of the engineering assumptions made by the EPA, they do not explain why the EPA was not justified in relying on OG&E’’s own consultant’’s model, or why the EPA’’s detailed responses in its technical support document were insufficient in addressing its concerns. For example, the petitioners state that ““the smaller scrubber envisioned by EPA [option 2] might work for some days of operation at the OG&E Units, but it would preclude OG&E from producing electricity at higher levels when needed.”” Pet. Opening Br. at 29 n.18. But the EPA assumed in its analysis that the plants would operate at a 100% capacity factor. Technical Support Document, JA at 1348. To be sure, our dissenting colleague raises a number of valid concerns about the EPA’’s actions, and we acknowledge that this is a close case. But, ultimately, we cannot adopt OG&E’’s analysis given that the EPA was aware of, and provided explanations contradicting, petitioners’’ comments.10 For instance, the petitioners contend that the EPA relied too heavily on the sulfur content of the fuel in downsizing the scrubbers. ““A scrubber must be sized to reflect the maximum potential heat input from the facility, and that number is essentially the same whether a facility burns high or 10 The dissent argues that ““[t]he EPA deserves no deference [on technical determinations], however, where it does not support a conclusion contradicting Oklahoma’’s first, reasonable, detailed technical analysis.”” Dissent at 3. However, the dissent does not disagree with our conclusion that the EPA had sufficient reasons for rejecting cost estimates——rife with errors——submitted by OG&E. It is not clear how the dissent reached the conclusion that, despite these errors, other portions of Oklahoma’’s analysis were ““reasonable.”” App. 34 low sulfur coal,”” the petitioners say. Pet. Opening Br. at 28. The EPA ““agree[d] that the sulfur content of the fuel, taken by itself, will not significantly affect the size (or cost) of the gas path portions of the FGD system.”” Response to Technical Comments, JA at 1283. However, the EPA noted that the ““design and sizing of a scrubber is generally divided into two major systems: (1) flue gas path and (2) reactant handling system.”” Id. at 1284. The EPA pointed out that OG&E’’s own consultant had said in a previous case that ““gross unit size in MW . . . and sulfur content of the fuel are the major variables”” needed ““in order to predict future retrofit costs.”” Id. at 1285. Ultimately, the EPA concluded that ““the use of the lower sulfur coal alone would reduce the capital cost of the scrubber by about $7 million or 3%.”” Id. at 1284. Given that we must defer to the EPA’’s technical judgments, we cannot say the EPA acted arbitrarily on the basis of the record before us and the petitioners’’ arguments in their brief. B. 2009 Cost Estimates The petitioners also argue that the EPA improperly adjusted the 2009 Cost Estimates in promulgating the FIP. Petitioners make three arguments. First, the petitioners argue that the EPA made unreasonable adjustments to the site-specific numbers put forth by petitioners. Second, the petitioners argue that the EPA improperly relied on the ““overnight”” cost method instead of the constant-dollar approach. Finally, the petitioners argue the EPA selectively manipulated many of the other input variables in order to force OG&E to install scrubbers. App. 35 1) Double Counting and Discounts The petitioners claim that in performing the analysis that formed the basis of the FIP, the EPA consultant arbitrarily discounted some of the costs that the petitioners had used in their analysis. Reviewing the record, we do not believe these adjustments were arbitrary or capricious. The EPA explained the basis for each of the adjustments it made. For example, the EPA discounted vendor quotes to reflect the likely efficiencies from building multiple identical units. Revised BART Cost-Effectiveness Analysis, JA at 1530-31. It applied a 5% discount after a ““search of the literature revealed a range of 4% to 10% savings from optimized equipment.”” Response to Technical Comments, JA at 1229. Further, the EPA provided an extensive response to the petitioners’’ comments on this point. The petitioners argued during the notice-and-comment period that the EPA should not have assumed that the quotes did not already contain a multiple-unit discount because the vendors knew they were constructing multiple units. In response, the EPA explained why it believed these quotes did not factor in efficiency discounts. Id. at 1228. OG&E had specifically asked for single-unit estimates; the prices OG&E used in its report were ““exactly double the per-unit prices in the vendor quotes.”” Id. at 1229. There was ““no evidence that any of these vendor quotes considered multiple unit discounts,”” even though ““[b]ased on common industry practice, [the EPA] expected to see vendor discounts for multiple units in OG&E’’s site specific cost estimates.”” Id. at 1228. In addition, one of the vendors specifically ““noted that the cost of the equipment and the design could be App. 36 optimized to provide more economical operation.”” Id. at 1229. Likewise, the EPA explained many of the other adjustments it made to the costs submitted by OG&E. For instance, OG&E’’s proposal estimated contingency costs at 14% of the total project capital cost plus escalation, without providing any details on how this number was calculated. Revised BART CostEffectiveness Analysis, JA at 1520. The consultant flagged this number as high, noting that the Control Cost Manual only permits the consideration of a limited number of contingency costs. ““A contingency factor in a cost effectiveness analysis ‘‘should be reserved (and applied to) only those items that could incur a reasonable but unanticipated increase but are not directly related to the demolition, fabrication, and installation of the system,’’”” the consultant said. Id. at 1521 (quoting Control Cost Manual, Chapter 2, Cost Estimation: Concepts and Methodology, Sec. 2.5.4, p. 2-30). In the absence of any justification for OG&E’’s estimate, the consultant adjusted contingency costs to the standard 3% of purchased equipment costs. Id. Similarly, the consultant adequately explained the decision to apply a discount to the ““owner’’s costs”” estimated by OG&E. OG&E estimated ““owner’’s cost”” at 5% of total capital expended, much higher than the 2% its consultant had used in other BART analyses. Id. at 1527. The EPA’’s consultant acknowledged that owners incur some costs related to construction. Id. But the consultant explained that many of the costs that OG&E included in its estimate of ““owner’’s costs””——such as site oversight——had already been included under the indirect capital costs of engineering/procurement and App. 37 construction. Id. In light of this, the consultant removed owner’’s costs from the analysis. Id. (““Owner’’s costs are not separately included in BART cost effectiveness analyses and have been more than double counted here.””). We do not believe these types of adjustments were arbitrary or capricious. Moreover, even after the EPA made these adjustments, at least some of these sitespecific costs were higher than the generic numbers the EPA could otherwise have used. See, e.g., id. at 1528 (““This change reduces the engineering and procurement costs by $12,733,100 at Sooner and by $12,944,277 at Muskogee. These values are still high compared to estimates based on the Cost Manual method of 10% purchased equipment costs.”” (footnotes omitted)). In fact, the EPA consultant concluded that the EPA’’s cost estimates were likely higher than actual costs would be. Id. at 1510 (““Actual costs could be even lower as I was unable to correct all of the overestimates that I identified due to lack of support and underlying calculations.””). 2) Constant-Dollar Basis Petitioners also argue that the EPA departed from the Control Cost Manual in removing costs aside from inflation from its estimates. As above, we see no merit to this argument. The petitioners have not made a persuasive case in their briefs that either the EPA’’s App. 38 methodology conflicts with the manual11 or that the EPA conceded it should only have excluded inflation. 3) Selective Manipulation Finally, the petitioners claim the EPA selectively manipulated its data to meet its desired result. The petitioners argue the EPA manipulated the data in three ways. First, petitioners argue that the EPA arbitrarily accepted some site-specific numbers and not others. Second, petitioners again reiterate complaints about the EPA’’s adjustments to its estimates. Third, petitioners argue that the EPA assumed too long of a useful life for the scrubbers. a) Site-specific costs First, the petitioners argue that the EPA chose only to adopt site-specific cost estimates that were higher than the generic estimates used in the manual. We cannot agree. As the EPA explained, it used these site-specific numbers when there was, in fact, accurate documentation——supporting a departure from the manual. Response to Technical Comments, JA at 1273 (““We used the Control Cost Methodology (overnight costs, no inflation, no AFUDC, no income taxes, etc.) and site-specific values when they were valuable and correct.””). Petitioners want us to view it as suspicious that the EPA accepted the site-specific estimates where they were lower than the generic numbers in the guidelines. But one could find it equally suspicious that 11 We are not necessarily endorsing the EPA’’s approach to costing methodology. We note only that the petitioners chose on appeal to abandon the arguments that they made in the administrative hearing that the manual did not support the EPA’’s methodology. App. 39 the petitioners did not provide documentation for its estimates that were much greater than the generic cost numbers in the manual. Given that many of the site-specific numbers provided to the EPA were not properly documented in accordance with the guidelines, we do not find it arbitrary or capricious that the EPA rejected them. b) Double counting The petitioners also argue that the EPA relied on flawed assumptions when it reduced some of the cost estimates for double counting or overestimation. Again, though, the consultant and the EPA thoroughly documented why they made these adjustments. We see no basis for reversing the EPA’’s decision on this ground. c) Useful life of scrubbers Finally, the petitioners argue that the EPA assumed too long of a useful life for the scrubbers. The longer the useful life of the scrubbers, the more cost effective they will appear to be. The EPA assumed a useful life of thirty years in its analysis. The petitioners argue that the EPA departed from the Control Cost Manual’’s standard useful life of twenty years for large pollution control systems. But the EPA adequately explained why it chose to assume a useful life of thirty years. As the petitioners acknowledge, the Control Cost Manual does not reference any specific useful life for scrubbers. See Pet. Opening Br. at 34. Therefore, the EPA considered, among other factors: 1) the fact that scrubbers installed between 1975 and 1985 are still in use; 2) the standards from cost estimates handbooks and App. 40 published papers, and 3) the fact that the EPA has assumed a 30-year lifetime for scrubbers since ““at least 1981.”” See JA at 1263. The petitioners do not explain why this explanation was inadequate.12 Instead, the petitioners argue that the EPA’’s decision was unjustified because the EPA assumed that the petitioners would use high-sulfur coal in analyzing Option 1, but then, in its response to the comments, said that the scrubbers would operate in the mild, low-sulfur environment in assuming a useful life of thirty years. This argument is premised on an inaccurate characterization of the EPA’’s comments. In 12 The petitioners characterize the EPA as departing from the manual’’s standard useful life of twenty years based solely on an unsupported determination ““that significant advances have been made in the material of construction and baghouse design since this publication.”” Pet. Opening Br. at 34. But the EPA was merely explaining that its thirty-year useful life for dry scrubbers was reasonable even in the context of the other control systems actually mentioned in the manual: OG&E also asserts that the Control Cost Manual assumes a 20 year useful life for other large air pollution systems, citing 20 years for a fabric filter baghouse and 20 years for SCR. The cite of 20 years for the baghouse actually says: ““For fabric filters, the system lifetime varies from 5 to 40 years, with 20 years being typical,”” citing to a 1980 report. Significant advances have been made in the material of construction and baghouse design since this publication. Further, the 1981 EPA/TVA report cited above, ““Technical Review of Dry FGD Sytems and Economic Evaluation of Spray Dryer FGD System”” assumes a 30 year economic and tax life for an SDA/FF, which includes the fabric filter. Regardless, our 30 year estimate for a scrubber, which includes a baghouse, is well within the reported range. Response to Technical Comments, JA at 1264 (footnotes omitted). App. 41 context, the EPA said that even scrubbers in high-sulfur environments have useful lives of at least thirty years: The subject application, the use of a scrubber to remove SO2 from low sulfur coal, is a mild environment for a scrubber, compared to high sulfur applications, which have already demonstrated 30 year lifetimes. The corrosion potential and bag plugging issues in a low sulfur application are much lower than in a comparable high sulfur application. Response to Technical Comments, JA at 1264 (emphasis added). Finally, the petitioners argue that the EPA has assumed a shorter useful life for scrubbers attached to other projects. However, the petitioners did not raise this particular argument regarding the useful life of the scrubbers during the administrative review period. Under the CAA, we may review ““[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment.”” 42 U.S.C. § 7607(d)(7)(B); see, e.g., Am. Farm Bureau Fed’’n v. EPA, 559 F.3d 512, 538 (D.C. Cir. 2009) (per curiam) (““In the comments submitted in response to the EPA’’s proposed revocation of the annual standard, the environmental petitioners argued only that the record evidence demonstrated adverse effects from long-term coarse PM exposure; they did not raise their current argument that an annual standard is necessary to prevent adverse effects from short-term exposure.””). The EPA raised this jurisdictional bar in its brief, EPA Response Br. at 43 n.9; the petitioners offered no response in their reply. Therefore, even if this App. 42 argument had merit, we decline to consider it in this petition for review. C. Scrubbers Would Not Have a Significant Impact on Visibility Finally, the petitioners assert that the emissions limits proposed in the FIP would not have a significant impact on visibility in the region. The petitioners argue: 1) that the EPA should have used the dollar-per-deciview method in evaluating the benefits to visibility in installing the scrubbers; and 2) that the EPA impermissibly aggregated the visibility improvements the scrubbers would create across facilities. Neither of these claims has merit. Oklahoma first suggests EPA should not have rejected the visibility analysis it conducted in the SIP, which used the dollar-per-deciview method. This argument is misguided. The EPA rejected the SIP because of the flawed cost estimates. When promulgating its own implementation plan, it did not need to use the same metric as Oklahoma. The guidelines merely permit the BART-determining authority to use dollar per deciview as an optional method of evaluating cost effectiveness. See 40 C.F.R. pt. 51 app. Y(IV)(E)(1).13 13 We note, however, that in both its final rule and in its brief the EPA asserts that the guidelines require the use of the dollar-per-ton metric in evaluating cost effectiveness. The guidelines themselves are a bit unclear. In the section on cost effectiveness, the guidelines mention only the dollar-per-ton metric. 40 C.F.R. pt. 51 app. Y(IV)(D)(4)(c). However, the guidelines later state that in evaluating alternatives, ““we recommend you develop a chart (or charts) displaying for each of App. 43 And in the final rule, the EPA explained why it did not use the dollar-per-deciview metric used by Oklahoma. ““Generally speaking, while the metric can be useful if thoughtfully applied, we view the use of the $/deciview metric as suggesting a level of precision in the calculation of visibility impacts that is not justified in many cases.”” 76 Fed. Reg. at 81,747. The EPA has never mandated the use of this metric, and has not developed ““thresholds of acceptable costs per deciview improvement.”” Id. While the federal land managers have developed threshholds, these threshholds were apparently developed without input from the EPA and without notice-and-comment review. EPA Br. at 54 n.13. In light of this, we do not find it arbitrary or capricious that the EPA chose not to use the dollar-per-deciview metric in evaluating BART options in creating the FIP. We therefore also conclude that any argument by the petitioners that the dollar-perdeciview measurement proves the scrubbers are not cost effective lacks merit. See Pet. Reply Br. at 16. The petitioners next argue that the EPA impermissibly aggregated the visibility improvements across facilities to make the scrubbers look more effective. The petitioners say that this is evidenced by the alternatives”” that includes, among other factors, the cost of compliance defined as ““compliance——total annualized costs ($), cost effectiveness ($/ton), and incremental cost effectiveness ($/ton), and/or any other cost-effectiveness measures (such as $/deciview).”” Id. app. Y(IV)(E)(1) (emphasis added). We do not rule here on whether the EPA would be justified in rejecting a SIP because it relied on the dollar-per-deciview metric. We hold only that it was reasonable for the EPA to use the dollar-per-ton metric despite Oklahoma’’s earlier analysis. App. 44 the EPA’’s reference to the total improvement in visibility (2.89 deciviews) that would result from placing scrubbers on all four of these units. Viewed separately, the improvements from the addition of scrubbers at each unit would not be worth the cost of the scrubbers, the petitioners say. While we agree that the EPA referenced the aggregated visibility improvement across the Class I areas, we do not agree that it used that number to guide its analysis. Instead, it evaluated the improvements facility-by-facility. The Response to the Technical Comments includes data on the visibility improvement at a number of different areas, broken down by facility. See JA at 1495-98. Further, the EPA said its modeling ““indicates that visibility improvements anticipated from the installation of dry scrubbers at each facility will result in reducing modeled impacts . . . from each facility at all nearby Class I areas to levels below 0.5 dv, with improvements greater than 1.0 dv at some Class I areas.”” See 76 Fed. Reg. at 81,739 (emphasis added). The petitioners also argue that the EPA erred because it considered the visibility improvement facility-by-facility instead of unit-by-unit. Even if this argument had merit, we have no jurisdiction to consider it. The petitioners never raised this objection during the rulemaking process. See 42 U.S.C. § 7607(d)(7)(B) (““Only an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.””). In fact, the petitioners actually commented that the EPA needed to make the visibility determinations on a App. 45 facility-by-facility basis. See JA at 1108 (““Whether reviewing a SIP or proposing its own FIP, EPA, like individual states, is required to consider the visibility improvement associated with scrubbers on a facility-by-facility basis.””). Likewise, the petitioners argue that the EPA did not provide sufficient notice of the approach it used in its final rule. The petitioners say the EPA used a new metric——days of visibility improvement——that it had never used before. Even if this argument has merit, we cannot consider it on appeal. Again, we may only address issues that were raised during the rulemaking process. As discussed above, it does not matter that the petitioners could not have raised their objection before the promulgation of the final rule. ““Rather, the CAA requires a petitioner to first raise its objection to the agency through a petition for reconsideration.”” Appalachian Power Co., 249 F.3d at 1066. We therefore decline to consider the petitioners’’ argument here. See 42 U.S.C. § 7607(d)(7)(B) (““If the Administrator refuses to convene [a reconsideration proceeding], such person may seek review of such refusal in the United States court of appeals for the appropriate circuit . . . .”” (emphasis added)). V In addition to these arguments concerning the EPA’’s substantive analysis, the petitioners raise a number of challenges to the procedures the EPA used in promulgating the rule. First, they argue that the EPA may not promulgate a FIP in the same action in which the agency disapproves a SIP. Second, the petitioners argue that the EPA lost the authority to promulgate a FIP because the agency failed to act App. 46 within two years after its duty to promulgate a FIP was first triggered. The CAA creates a high bar for any petitioner challenging an EPA action on procedural grounds. The petitioner must prove: 1) that the failure to observe the procedure was ““arbitrary and capricious””; 2) that the objection was ““raised with reasonable specificity during the period for public comment””; and 3) that the errors were ““so serious and related to matters of such central relevance to the rule that there is a substantial likelihood that the rule would have been significantly changed if such errors had not been made.”” 42 U.S.C. § 7607(d)(9)(D), (d)(7), (d)(8). ““The essential message of so rigorous a standard is that Congress was concerned that EPA’’s rulemaking not be casually overturned for procedural reasons, and we of course must respect that judgment.”” Sierra Club v. Costle, 657 F.2d 298, 391 (D.C. Cir. 1981). The petitioners first argue that the EPA violated required procedures by promulgating its FIP in the same action in which it disapproved the SIP. The petitioners argue the statute requires the EPA first take action on the SIP because it says, according to petitioners, that the ““EPA shall propose a FIP ‘‘unless the State corrects the deficiency,’’ thereby reflecting Congress’’s intention for States to have the power to design their own SIP and have an opportunity to correct a SIP before a FIP is issued.”” Pet. Opening Br. at 40 (quoting § 7410(c)). It also makes a policy argument that permitting the EPA to disapprove SIPs in the same action in which it promulgates a FIP will ““blur [the] distinction”” between the EPA’’s role in reviewing SIPs and promulgating FIPs. Id. at 41. App. 47 We do not agree that the EPA’’s actions violated the procedural requirements of the CAA. The petitioners’’ parsing of the statute relies on a truncated quotation. Under 42 U.S.C. § 7410(c)(1), the EPA must create a FIP after either the state has failed to make the required SIP submission or the EPA has disapproved part of the state’’s SIP. This duty continues to exist ““unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such Federal implementation plan.”” § 7410(c)(1) (emphasis added). Once the EPA issued findings that Oklahoma failed to submit the required SIP under the Regional Haze Rule, the EPA had an obligation to promulgate a FIP. The statute itself makes clear that the mere filing of a SIP by Oklahoma does not relieve the EPA of its duty. And the petitioners do not point to any language that requires the EPA to delay its promulgation of a FIP until it rules on a proposed SIP. As the EPA points out, such a rule would essentially nullify any time limits the EPA placed on states. States could forestall the promulgation of a FIP by submitting one inadequate SIP after another. In any case, even if we agreed that the EPA should not have promulgated the FIP in the same action as it rejected the SIP, it is not clear the petitioners would meet the high bar for overturning an EPA action on procedural grounds. It may be poor policy to try to distinguish between the SIP and FIP in a single action. But the petitioners make no attempt to show the procedural error was ““so serious and related to matters of such central relevance to the rule that there is a substantial likelihood that the rule would have been significantly changed if such errors had not been App. 48 made.”” § 7607(d)(9)(D), (d)(8). Indeed, after the EPA raised this heightened standard of review of procedural actions in its brief, the petitioners were silent as to any issue regarding this procedural deficiency in their reply brief. The petitioners also assert the EPA violated the statute because § 7410(c)(1) says that the ““Administrator shall promulgate a Federal implementation plan at any time within 2 years after”” the EPA’’s duty to promulgate a FIP is triggered. The petitioners argue the EPA lost authority to promulgate its FIP because more than two years had passed since the EPA made its initial finding that Oklahoma failed to submit a SIP. Although the statute undoubtedly requires that the EPA promulgate a FIP within two years, it does not stand to reason that it loses its ability to do so after this two-year period expires. Rather, the appropriate remedy when the EPA violates the statute is an order compelling agency action. The Supreme Court rejected an argument similar to the petitioners’’ argument in Brock v. Pierce County, 476 U.S. 253 (1986). At issue in Brock was a law requiring that the Secretary of Labor ““issue a final determination as to the misuse of [Comprehensive Employment and Training Act] funds by a grant recipient within 120 days after receiving a complaint alleging such misuse.”” Brock, Id. at 254-55 (quotation omitted). The petitioners in that case argued that the Secretary lost his power to recover those funds if he did not make a final determination within 120 days. Id. at 255. In the absence of a more clear statutory directive, the Court refused to accept this argument. Rather, App. 49 when ““there are less drastic remedies available for failure to meet a statutory deadline””——such as a motion to compel agency action——““courts should not assume that Congress intended the agency to lose its power to act.”” Id. at 260. The Court ““would be most reluctant to conclude that every failure of an agency to observe a procedural requirement voids subsequent agency action, especially when important public rights are at stake.”” Id. The petitioners do not explain why the principles of Brock would not also control this case. The provision here is ““clearly intended to spur [the EPA] to action, not to limit the scope of [its] authority.”” Id. at 265. In the absence of any other indication from Congress, the appropriate remedy is simply a suit to compel agency action, not to eliminate the EPA’’s authority to file a FIP. See Mont. Sulphur & Chem. Co. v. EPA, 666 F.3d 1174, 1190-91 (9th Cir. 2012). VI In conclusion, we hold that the EPA had the authority to review Oklahoma’’s BART determinations. Moreover, it exercised that authority properly. Accordingly, we DENY the petition for review of the EPA’’s final rule. The stay pending hearing by the merits panel is hereby lifted. KELLY, Circuit Judge, concurring in part and dissenting in part. Although I agree with much of the court’’s analysis, I dissent with respect to whether certain EPA actions were arbitrary and capricious. See Ct. Op. Pt. IV(A) App. 50 (analyzing the EPA’’s calculations of baseline emissions and its determination regarding the technical feasibility of the smaller scrubbers on which it based its cost/benefit analysis). Therefore, I would grant the petition for review. As an initial matter, the court states that ““[w]e review these challenges [to the EPA’’s FIP] under the same arbitrary and capricious standard we used to evaluate the EPA’’s rejection of the SIP.”” Ct. Op. Pt. IV. The court notes, however, that ““we do so while recognizing this requires a slightly different perspective: evaluating the EPA’’s own choices under the guidelines, as opposed to evaluating its choice to reject the Oklahoma SIP under the guidelines.”” Id.; see also id. at Pt. III(B), n.7 (““We recognize that the EPA has less discretion when it takes actions to reject a SIP than it does when it promulgates a FIP.””). That may usually be the case, but here the EPA rejected Oklahoma’’s SIP and promulgated its own FIP in the same rulemaking action. Many of the same reasons for rejecting the SIP were used to justify the FIP. Therefore, to the extent it makes a difference, I am not convinced we owe any more deference to the EPA in evaluating these challenges than we would if this action were solely a rejection of a state SIP. The EPA rejected Oklahoma’’s cost estimates for scrubbers and provided two options of its own. These options arbitrarily and capriciously (1) assumed OG&E would burn coal they are not burning and have no plans to burn and (2) used scrubbers that do not fit and are not technically feasible. For purposes of the cost benefit analysis, the Control Cost Manual (CCM) requires that anticipated App. 51 annual emissions be calculated based upon past actual emissions. 40 C.F.R. pt. 51, App. Y(IV)(D)(4)(d). The EPA ignored the historical emissions baseline in Option 1. OG&E has been using low-sulfur coal and its continued use would have resulted in scrubbers removing about 14,000 tons of SO2 per year at each affected power plant. JA 1106. The EPA, however, assumed that OG&E would begin using high-sulfur coal which would result in the removal of between roughly 43,000 to 46,000 tons of SO2 per year at each affected power plant. Id. at 1106, 1513––14. Petitioners commented that any assumption by the EPA of a change in coal was improper and unsupportable. See id. at 1088, 1096––99 (OG&E EPA comments); see also id. at 300––02, 313 (OG&E state comments). Knowing these calculations violated the manual, the EPA developed Option 2. Option 2 was based on OG&E’’s continued use of low-sulfur coal——the correct emissions baseline as required by the CCM. However, the EPA changed the size of the scrubbers to smaller, less expensive ones. Id. at 1514––16. Petitioners argued extensively that these smaller scrubbers were technically infeasible. See, e.g., id. at 1099––1102. In particular, the comments point out the size of a scrubber is not dependent on the type of coal used but on gas flow and the maximum potential heat input. Id. at 1101––02, 1144 (OG&E EPA comments); see also id. at 384––430 (OG&E state comments). EPA admitted in response that the type of coal alone does not affect scrubber size and its estimate for a smaller scrubber was a result of oversimplification. See id. at 1283––84. Therefore, the only question is App. 52 whether the EPA provided support for the technical feasibility of the smaller scrubbers it ultimately required. The EPA, however, relies almost exclusively on a cost model by OG&E’’s consultant Sargent & Lundy in a different action and its statements that the amount of SO2 removed can in fact affect scrubber size at least somewhat. See id. at 1283, 1348. This report does not describe why it matters or how it would affect the size of the scrubbers in this case. The EPA rejected Oklahoma’’s evidentiary support with no clear evidence of its own to support its contrary conclusion. Usually the court grants deference to the EPA’’s technical determinations. See San Juan Citizens Alliance v. Stiles, 654 F.3d 1038, 1045 (10th Cir. 2011). The EPA deserves no such deference, however, where it does not support a conclusion contradicting Oklahoma’’s first, reasonable, detailed technical conclusion. See JA 384––430; Lockheed Martin Corp. v. Admin. Review Bd., U.S. Dep’’t of Labor, No. 11-9524, 2013 WL 2398691, at *3 (10th Cir. June 4, 2013). Therefore I would conclude that the failure of the agency to provide any evidence that a significantly smaller scrubber was sufficient to meet OG&E’’s needs is arbitrary and capricious. Finally, it is worth noting that the EPA’’s regional haze program is distinct in the amount of power given to the states. See, e.g., Train v. Nat. Res. Def. Council, Inc., 421 U.S. 60, 79 (1975); 70 Fed. Reg. 39,104, 39,137 (July 6, 2005) (““[H]ow states make BART determinations or how they determine which sources are subject to BART”” are among the issues ““where the Act and legislative history indicate that Congress evinced a special concern with insuring that States App. 53 would be the decision makers.””). There are a number of reasons for this approach, not the least of which is that its goals and standards are purely aesthetic rather than directly related to health and safety. The EPA’’s rule here requires OG&E to make a $1.2 billion dollar investment over the next five years that will, even under EPA’’s estimate, result in no appreciable change in visibility. Moreover, there is no evidence this investment will have any effect whatsoever on air quality. It surely will, however, result in adverse changes to what Oklahoma ratepayers will pay for electricity. Although the EPA has at least some authority to review BART determinations within a state’’s SIP, it has no authority to condition approval of a SIP based simply on a preference for a particular control measure. Texas v. EPA, 690 F.3d 670, 684 (5th Cir. 2012); see EME Homer City Generation, L.P. v. EPA, 696 F.3d 7, 29 (D.C. Cir. 2012) (reviewing a different rule and concluding that the CAA ““prohibits EPA from using the SIP process to force States to adopt specific control measures””). Oklahoma considered the cost and resulting benefit of such a large investment in scrubbers, and its conclusion was not unreasonable. Assuming the EPA has authority to review Oklahoma’’s SIP in the manner it did, its rejection of the SIP and promulgation of its own FIP was arbitrary and capricious. Accordingly, I respectfully dissent on this issue. App. 54 UNITED STATES COURT OF APPEALS FOR THE TENTH CIRCUIT [Filed July 19, 2013] No. 12-9526 _______________________________________ STATE OF OKLAHOMA; OKLAHOMA ) INDUSTRIAL ENERGY CONSUMERS, ) an unincorporated association, ) Petitioners, ) ) v. ) ) UNITED STATES ENVIRONMENTAL ) PROTECTION AGENCY, ) Respondent. ) --------------------------------------------------------- ) SIERRA CLUB, ) Intervenor - Respondent, ) ) and ) ) PACIFICORP; AMERICAN COALITION ) FOR CLEAN COAL ELECTRICITY; ) NATIONAL PARKS ) CONSERVATION ASSOCIATION, ) Amici Curiae. ) _______________________________________) No. 12-9527 _______________________________________ OKLAHOMA GAS & ELECTRIC ) COMPANY, ) Petitioner, ) ) App. 55 v. ) ) UNITED STATES ENVIRONMENTAL ) PROTECTION AGENCY, ) Respondent. ) --------------------------------------------------------- ) SIERRA CLUB, ) Intervenor - Respondent, ) ) and ) ) PACIFICORP; AMERICAN COALITION ) FOR CLEAN COAL ELECTRICITY; ) NATIONAL PARKS CONSERVATION ) ASSOCIATION, ) Amici Curiae. ) _______________________________________) JUDGMENT Before BRISCOE, Chief LUCERO, Circuit Judges. Judge, KELLY and This petition for review originated from the United States Environmental Protection Agency and was argued by counsel. It is the judgment of this Court that the action of the United States Environmental Protection Agency is affirmed. Entered for the Court /s/ Elisabeth A. Shumaker ELISABETH A. SHUMAKER, Clerk App. 56 APPENDIX B 81728 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 52 [EPA––R06––OAR––2010––0190; FRL––9608––4] Approval and Promulgation of Implementation Plans; Oklahoma; Federal Implementation Plan for Interstate Transport of Pollution Affecting Visibility and Best Available Retrofit Technology Determinations AGENCY: Environmental Protection Agency (EPA). ACTION: Final rule. SUMMARY: EPA is partially approving and partially disapproving a revision to the Oklahoma State Implementation Plan (SIP) submitted by the State of Oklahoma through the Oklahoma Department of Environmental Quality on February 19, 2010, intended to address the regional haze requirements of the Clean Air Act (CAA). In addition, EPA is partially approving and partially disapproving a portion of a revision to the Oklahoma SIP submitted by the State of Oklahoma on May 10, 2007 and supplemented on December 10, 2007 to address the requirements of CAA section 110(a)(2)(D)(i)(II) as it applies to visibility for the 1997 8-hour ozone and 1997 fine particulate matter National App. 57 Ambient Air Quality Standards. This CAA requirement is intended to prevent emissions from one state from interfering with the visibility programs in another state. EPA is approving certain core elements of the SIP including Oklahoma’’s: determination of baseline and natural visibility conditions; coordinating regional haze and reasonably attributable visibility impairment; monitoring strategy and other implementation requirements; coordination with states and Federal Land Managers; and a number of NOX, SO2, and PM BART determinations. EPA is finding that Oklahoma’’s regional haze SIP did not address the sulfur dioxide Best Available Retrofit Technology requirements for six units in Oklahoma in accordance with the Regional Haze requirements, or the requirement to prevent interference with other states’’ visibility programs. EPA is promulgating a Federal Implementation Plan to address these deficiencies by requiring emissions to be reduced at these six units. This action is being taken under section 110 and part C of the CAA. DATES: This final rule is effective on: January 27, 2012. ADDRESSES: EPA has established a docket for this action under Docket ID No. EPA––R06–– OAR––2010––0190. All documents in the docket are listed in the Federal eRulemaking portal index at http://www.regulations.gov and are available either electronically at http://www.regulations.gov or in hard copy at EPA Region 6, 1445 Ross Ave., Dallas, TX, 75202––2733. To inspect the hard copy materials, please schedule an appointment during normal business hours with the contact listed in the FOR FURTHER App. 58 INFORMATION CONTACT section. A reasonable fee may be charged for copies. FOR FURTHER INFORMATION CONTACT: Joe Kordzi, EPA Region 6, (214) 665––7186, kordzi.joe@epa.gov. SUPPLEMENTARY INFORMATION: Throughout this document wherever ““we,”” ““us,”” ““our,”” or ““the Agency”” is used, we mean the EPA. Overview The CAA requires that states develop and implement SIPs to reduce the pollution that causes visibility impairment over a wide geographic area, known as Regional Haze (RH). CAA sections 110(a) and 169A. Oklahoma submitted a RH plan to us on February 19, 2010. On March 22, 2011, we proposed to partially approve and partially disapprove certain elements of Oklahoma’’s SIP. 76 FR 16168. Today, we are taking final action by partially approving and partially disapproving the elements of Oklahoma’’s RH SIP addressed in our proposed rule. As discussed in the proposal for this rule, the CAA requires us to promulgate a Federal Implementation Plan (FIP) if a state fails to make a required SIP submittal or we find that the state’’s submittal is incomplete or unapprovable. CAA section 110(c)(1). Therefore, we are promulgating a FIP to address the deficiencies in Oklahoma’’s RH plan. One important element of the RH requirements of the CAA is that the Best Available Retrofit Technology (BART) must be selected and implemented for certain sources. The process of establishing BART emission limitations can be logically broken down into three App. 59 steps. First, states identify those sources which meet the definition of ““BART-eligible source”” set forth in 40 CFR 51.301. Second, states determine whether such sources ““emit any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area”” (a source which fits this description is ““subject to BART””). Third, for each source subject to BART, states then identify the appropriate type and the level of control for reducing emissions,”” by conducting a five-step analysis: Step 1: Identify All Available Retrofit Control Technologies, Step 2: Eliminate Technically Infeasible Options, Step 3: Evaluate Control Effectiveness of Remaining Control Technologies, Step 4: Evaluate Impacts and Document the Results, and Step 5: Evaluate Visibility Impacts. We agree with Oklahoma’’s identification of sources that are BART eligible and subject to BART. In addition, we are approving a number of BART determinations from Oklahoma’’s RH SIP. We are not able to approve Oklahoma’’s sulfur dioxide (SO2) BART determinations for the OG&E’’s Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the AEP/PSO Northeastern Units 3 and 4. In reviewing the SO2 BART determinations for these six units,1 we noted the state’’s cost estimates for SO2 scrubbers were high in comparison to other similar units, and we therefore separately assessed the costs of installation of controls 1 When we say ““six BART sources,”” or ““six units,”” we mean Units 4 and 5 of the Oklahoma Gas and Electric Muskogee plant in Muskogee County; Units 1 and 2 of the Oklahoma Gas and Electric Sooner plant in Noble County; and Units 3 and 4 of the American Electric Power/Public Service Company of Oklahoma Northeastern plant in Rogers County. App. 60 for these units using well established costing methodologies for BART determinations. As a result of this review, we proposed disapproval of the Oklahoma’’s SO2 BART determinations for these six units because the Oklahoma’’s costing methodology was not in accordance with RH requirements. Consistent with the disparity in cost estimations we identified in our proposed disapproval, our revised cost estimate indicates that dry scrubber control technology is about ½ to ¾ less expensive than was calculated by Oklahoma. We have therefore determined it is appropriate to finalize our proposed disapproval of the Oklahoma’’s SO2 BART determinations for the six units, because we conclude that the flaws in the state’’s cost estimations were significant, and that the state therefore lacked adequate record support and a reasoned basis for its determinations regarding the cost effectiveness of controls as needed for the final steps of the BART analysis and as required by the RH Rule (RHR). We are also disapproving the state’’s submitted Long Term Strategy because it relies on these BART limits which we are disapproving. We will of course consider, and would prefer, approving a SIP if the state submits a revised plan for these units that we can approve. We are approving the remaining sections of the RH SIP submission. This includes certain core elements of the SIP including Oklahoma’’s (1) determination of baseline and natural visibility conditions, (2) coordinating regional haze and reasonably attributable visibility impairment, (3) monitoring strategy and other implementation requirements, (4) coordination with states and Federal Land App. 61 Managers, and (5) the following BART determinations from Oklahoma’’s RH SIP: •• The SO2, nitrogen oxides (NOX), and particulate matter (PM) BART determinations for the Oklahoma Gas and Electric (OG&E) Seminole Units 1, 2, and 3. •• The NOX and PM BART determinations for OG&E’’s Sooner Units 1 and 2. •• The NOX and PM BART determinations for the OG&E Muskogee Units 4 and 5. •• The SO2, NOX, and PM BART determinations for the American Electric Power/Public Service Company of Oklahoma (AEP/PSO) Comanche Units 1 and 2. •• The SO2, NOX, and PM BART determinations for the AEP/PSO Northeastern Unit 2. •• The NOX and PM BART determination for the AEP/PSO Northeastern Units 3 and 4. •• The SO2, NOX, and PM BART determination for the AEP/PSO Southwestern Unit 3. In addition to the Regional Haze Requirements, CAA section 110(a)(2)(D)(i)(II) requires that the Oklahoma SIP ensure that emissions from sources within Oklahoma do not interfere with measures required in the SIP of any other state under part C of the CAA to protect visibility. This requirement is commonly referred to as the visibility prong of ““interstate transport,”” which is also called the ““good neighbor”” provision of the CAA. Oklahoma submitted a SIP to meet the requirements of interstate transport for the 1997 8-hour ozone National Ambient Air Quality Standards (NAAQS) and the fine particulate App. 62 matter (PM2.5) NAAQS on May 10, 2007, and supplemented it on December 10, 2007. In the May 10, 2007, submittal, Oklahoma stated that it intended for its RH submittal to satisfy the requirements of the visibility prong. We proposed to partially approve and partially disapprove this submission as it relied upon the Regional Haze SIP that we were proposing to partially approve and partially disapprove. In evaluating whether Oklahoma’’s SIP ensures that emissions from sources within Oklahoma do not interfere with the visibility programs of other states, we found that the regional modeling conducted by the Central Regional Air Programs (CENRAP), participated in by Oklahoma, included reductions at the six units that were not required by the Oklahoma SIP. Since this modeling was used by other states and Oklahoma in establishing their Reasonable Progress Goals, we find that the Oklahoma SIP does not ensure that emissions from sources within Oklahoma do not interfere with measures required in the SIP of any other state under Part C of the CAA to protect visibility. To address the deficiencies identified in our disapproval of these SO2 BART determinations and the disapproval of the SIP submission as it pertains to the visibility prong of interstate transport, we are finalizing a FIP to control emissions from the six units. Our FIP requires that these six units reduce emissions of SO2 to improve the scenic views at four national parks and wilderness areas: the Caney Creek and Upper Buffalo Wilderness Areas in Arkansas, the Wichita Mountains National Wildlife Refuge in Oklahoma, and the Hercules Glades Wilderness Area in Missouri. Improved air quality also results in public App. 63 health benefits. This FIP can be replaced by a future state plan that meets the applicable CAA requirements. All six units are coal-fired electricity generating units. Our FIP requires the six units to reduce their SO2 pollution to an emission rate of 0.06 pounds per million BTU, calculated on the basis of a rolling 30 boiler operating day average. This can be accomplished by retrofitting the six units with dry flue gas desulfurization technology, commonly known as ““SO2 scrubbers.”” In addition, any technology that can meet this SO2 emission limit may be implemented at the six subject units. For example, EPA believes that these limits can also be met by wet scrubbing technology or switching to natural gas. We held a 60 day public comment period on this action, and an open house and a public hearing in both Tulsa and Oklahoma City. Many public commenters disagreed with aspects of our cost analysis for SO2 BART for the six affected units. After careful review of information provided during the public comment period, we revised our calculation of the total project cost for the four OG&E units from our proposed range of approximately $312,423,000 to $605,685,000, to our final range of approximately $589,237,000 to $607,461,000. We made no changes to the cost basis for the two AEP/PSO units from our proposal. As such, the associated cost investment for AEP/PSO is $274,100,000. Even with these changes to our cost analysis we conclude that we cannot approve the SIP’’s SO2 emission limits and instead must adopt the proposed emission limits for the six units. However, in consideration of comments about the time needed to App. 64 comply with our FIP, we have extended the time for compliance with the SO2 emission limit from the proposed three years to five years. This investment will reduce the visibility impacts due to these facilities by over 60 to 80% at each one of the four national parks and wilderness areas in the area, and promote local tourism by decreasing the number of days when pollution impairs scenic views. Although today’’s action is taken to address visibility impairments, we believe it will also reduce public health impacts by decreasing SO2 pollution by approximately 95%. This action is being taken under section 110 and part C of the CAA. Table of Contents I. Summary of Our Proposal A. Regional Haze B. Interstate Transport of Pollutants and Visibility Protection II. Final Decision A. Regional Haze B. Interstate Transport of Pollutants and Visibility Protection C. Compliance Timeframe III. Analysis of Major Issues Raised by Commenters A. Comments Generally Favoring Our Proposal B. Comments Generally Against Our Proposal App. 65 C. Comments on Legal Issues 1. General Legal Comments 2. Comments Asking EPA To Consider All Rules 3. Comments on Interstate Transport D. Comments on Modeling E. Summary of Responses to Comments on the SO2 BART Cost Calculation 1. Control Cost Manual Methodology 2. Revised Cost Calculations for the OG&E Units 3. Cost Calculations for the AEP/PSO Units 4. Conclusion F. Summary of Responses to Visibility Improvement Analysis Comments G. Summary of Responses to Comments Received on the SO2 BART Emission Limit H. Summary of Responses to Comments Received on the SO2 BART Compliance Timeframe I. Comments Supporting Conversion to Natural Gas and/or Renewable Energy Sources J. Comments Arguing Our Proposal Would Hurt the Economy and/or Raise Electricity Rates App. 66 K. Comments Arguing Our Proposal Would Help the Economy L. Comments on Health and Benefits and Other Pollutants Ecosystem M. Miscellaneous Comments IV. Statutory and Executive Order Reviews I. Summary of Our Proposal On March 22, 2011, we published the proposal on which we are now taking final action. 76 FR 16168. We proposed to partially approve and partially disapprove Oklahoma’’s RH SIP revision submitted on February 19, 2010. We also proposed to partially approve and partially disapprove a portion of a SIP revision we received from the State of Oklahoma on May 10, 2007, as supplemented on December 10, 2007, for the purpose of addressing the ““good neighbor”” provisions of the CAA section 110(a)(2)(D)(i)(II) with respect to visibility for the 1997 8-hour ozone NAAQS and the PM2.5 NAAQS. A. Regional Haze We proposed to approve Oklahoma’’s determination that Units 4 and 5 of the OG&E Muskogee plant, Units 1 and 2 of the OG&E Sooner plant, and Units 3 and 4 of the AEP/PSO Northeastern plant are subject to BART under 40 CFR 51.308(e). However, we proposed to disapprove the SO2 BART determinations for Units 4 and 5 of the OG&E Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; and Units 3 and 4 of the AEP/PSO Northeastern plant because they do not comply with our regulations under 40 CFR 51.308(e). App. 67 We also proposed to disapprove the long term strategy (LTS) under section 51.308(d)(3) because Oklahoma has not shown that the strategy is adequate to achieve the reasonable progress goals set by Oklahoma and by other nearby states. The visibility modeling Oklahoma used to support its SIP revision submittal assumed SO2 reductions from the six sources identified above that Oklahoma did not secure when making its BART determinations for these sources. The Oklahoma Department of Environmental Quality (ODEQ) participated in the Central Regional Air Planning Association (CENRAP) visibility modeling development that assumed certain SO2 reductions from these six BART sources. ODEQ also consulted with other states with the understanding that these reductions would be secured. We proposed a FIP to address these defects in BART and the LTS. We proposed a FIP that included SO2 BART emission limits on these sources. We proposed that SO2 BART for Units 4 and 5 of the OG&E Muskogee plant, Units 1 and 2 of the OG&E Sooner plant, and Units 3 and 4 of the AEP/PSO Northeastern plant is an SO2 emission limit of 0.06 lbs/MMBtu that applies individually to each of these units on a rolling 30 day calendar average. Additionally, we proposed monitoring, recordkeeping, and reporting requirements to ensure compliance with these emission limitations. We proposed that compliance with the emission limits be within three years of the effective date of our final rule. We solicited comments on alternative timeframes, of from two years up to five years from the effective date of our final rule. We also proposed that, should OG&E and/or AEP/PSO elect to reconfigure the above units to burn natural gas as a means of satisfying their App. 68 BART obligations under section 51.308(e), conversion should be completed within the same time frame. We solicited comments as to, considering the engineering and/or management challenges of such a fuel switch, whether the full five years allowed under section 51.308(e)(1)(iv) following our final approval would be appropriate. We proposed to disapprove section VI.E of the Oklahoma RH SIP entitled, ““Greater Reasonable Progress Alternative Determination.”” We also proposed to disapprove the separate executed agreements between ODEQ and OG&E, and ODEQ and AEP/PSO entitled ““OG&E Regional Haze Agreement, Case No. 10––024,”” and ““PSO Regional Haze Agreement, Case No. 10––025,”” housed within Appendix 6––5 of the RH SIP. We proposed that these portions of the submittal are severable from the BART determinations and the LTS. These alternative determinations are not fundamental requirements of a RH program, so disapproval of them does not create a regulatory gap in the SIP. Therefore, no FIP is required. We proposed no action on whether Oklahoma has satisfied the reasonable progress requirements of EPA’’s regional haze SIP requirements found at section 51.308(d)(1). We also proposed to approve the remaining sections of the RH SIP submission. B. Interstate Transport of Pollutants and Visibility Protection We proposed to partially approve and partially disapprove a portion of a SIP revision we received from the State of Oklahoma on May 10, 2007, as App. 69 supplemented on December 10, 2007, for the purpose of addressing the ““good neighbor”” provisions of the CAA section 110(a)(2)(D)(i) with respect to visibility for the 1997 8-hour ozone NAAQS and the PM2.5 NAAQS. This proposal addressed the requirement of section 110(a)(2)(D)(i)(II) that emissions from Oklahoma sources do not interfere with measures required in the SIP of any other state under part C of the CAA to protect visibility. Having proposed to disapprove these provisions of the Oklahoma SIP, we proposed a FIP to address the requirements of section 110(a)(2)(D)(i)(II) with respect to visibility to ensure that emissions from sources in Oklahoma do not interfere with the visibility programs of other states. We proposed to find that the controls proposed under the proposed FIP, in combination with the controls required by the portion of the Oklahoma RH submittal that we proposed to approve, will serve to prevent sources in Oklahoma from emitting pollutants in amounts that will interfere with efforts to protect visibility in other states. II. Final Decision A. Regional Haze We are partially approving, partially disapproving, and taking no action on various portions of Oklahoma’’s RH SIP revision submitted on February 19, 2010. We are finalizing a FIP to address the defects in those portions of this SIP that are mandatory requirements that we are disapproving. We are disapproving the SO2 BART determinations for Units 4 and 5 of the Oklahoma OG&E Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; and App. 70 Units 3 and 4 of the AEP/PSO Northeastern plant. We are disapproving the LTS under section 51.308(d)(3). We are finalizing a FIP that specifically imposes SO2 BART emission limits on these sources. We find that SO2 BART for Units 4 and 5 of the OG&E Muskogee plant, Units 1 and 2 of the OG&E Sooner plant, and Units 3 and 4 of the AEP/PSO Northeastern plant is an SO2 emission limit of 0.06 lbs/MMBtu that applies individually to each of these units. As we discuss elsewhere in this action and in a supplemental response to comments document (Supplemental RTC),2 we find there is ample support for this decision. However, in response to a comment we received, we are changing our proposed averaging period for these emission limits from a straight rolling 30 day calendar average to one calculated on the basis of a boiler operating day (BOD). We also received a comment requesting that we revise our proposed unit-by-unit SO2 limit, and replace it with a plant wide average SO2 limit. As we note in our response to this comment, although we are open to combining the BOD and plant wide averaging techniques, this presents a significant 2 The full title of the Supplemental RTC document is the ““Response to Technical Comments for Sections E through H of the Federal Register Notice for the Oklahoma Regional Haze and Visibility Transport FIP,”” and it is available in the docket for this rulemaking. This document is referred to as the ““Supplemental RTC”” throughout this rulemaking. We received many lengthy, and highly technical, comments concerning our SO2 BART cost analysis, the visibility improvement analysis, the emission limit, and the compliance timeframe. While this notice generally addresses all of the issues commenters raised, the Supplemental RTC is intended to address comments on these four categories in greater detail. App. 71 technical challenge in having a verifiable, workable, and enforceable algorithm for calculating such an average. Due to our obligation to ensure the enforceability of the emission limits we are imposing in our FIP and the technical challenges of meeting that obligation through a plant wide limit, we are not including a plant wide average SO2 limit in our final FIP. We leave it to Oklahoma to take up this matter in a future SIP revision, should it decide to do so. We are confident that this issue can be addressed prior to the installation of the emission controls required to satisfy our FIP. We are promulgating monitoring, recordkeeping, and reporting requirements to ensure compliance with these emission limitations. We are disapproving section VI.E of the Oklahoma RH SIP entitled, ““Greater Reasonable Progress Alternative Determination.”” We are also disapproving the separate executed agreements between ODEQ and OG&E, and ODEQ and AEP/PSO entitled ““OG&E Regional Haze Agreement, Case No. 10––024,”” and ““PSO Regional Haze Agreement, Case No. 10––025,”” housed within Appendix 6––5 of the RH SIP. We find that these portions of the submittal are severable from the BART determinations and the LTS. These alternative determinations are not fundamental requirements of a RH program, so disapproval of them does not create a gap in the SIP. For these reasons, no FIP is required. We are taking no action on whether Oklahoma has satisfied the reasonable progress requirements of EPA’’s RH SIP requirements found at section 51.308(d)(1). App. 72 We are approving the remaining sections of the RH SIP submission. This includes certain core elements of the SIP including Oklahoma’’s (1) determination of baseline and natural visibility conditions, (2) coordinating regional haze and reasonably attributable visibility impairment, (3) monitoring strategy and other implementation requirements, (4) coordination with states and Federal Land Managers, and (5) the following BART determinations from Oklahoma’’s RH SIP: •• The SO2, nitrogen oxides (NOX), and particulate matter (PM) BART determinations for the Oklahoma Gas and Electric (OG&E) Seminole Units 1, 2, and 3. •• The NOX and PM BART determinations for OG&E’’s Sooner Units 1 and 2. •• The NOX and PM BART determinations for the OG&E Muskogee Units 4 and 5. •• The SO2, NOX, and PM BART determinations for the American Electric Power/Public Service Company of Oklahoma (AEP/PSO) Comanche Units 1 and 2. •• The SO2, NOX, and PM BART determinations for the AEP/PSO Northeastern Unit 2. •• The NOX and PM BART determination for the AEP/PSO Northeastern Units 3 and 4. •• The SO2, NOX, and PM BART determination for the AEP/PSO Southwestern Unit 3. App. 73 B. Interstate Transport of Pollutants and Visibility Protection We are partially approving and partially disapproving a portion of a SIP revision we received from the State of Oklahoma on May 10, 2007, as supplemented on December 10, 2007, for the purpose of addressing the ““good neighbor”” provisions of the CAA section 110(a)(2)(D)(i) with respect to visibility for the 1997 8-hour ozone NAAQS and the PM2.5 NAAQS. We are finalizing a FIP to address the requirements of section 110(a)(2)(D)(i)(II) with respect to visibility to ensure that emissions from sources in Oklahoma do not interfere with the visibility programs of other states. We find that the controls under this FIP, in combination with the controls required by the portion of the Oklahoma RH submittal that we are approving, will serve to prevent sources in Oklahoma from emitting pollutants in amounts that will interfere with efforts to protect visibility in other states. C. Compliance Timeframe In response to comments we received, we find that compliance with the emission limits of our FIP must be within five years of the effective date of this rule. This compliance timeframe includes the election to reconfigure the six units to burn natural gas. III. Analysis Commenters of Major Issues Raised by We received both written comments and oral comments at the Public Hearings in Oklahoma City and Tulsa. We also received comments by the Internet and the mail. The comments are summarized and App. 74 discussed below. The full text received from these commenters is included in the docket associated with this action. A. Comments Generally Favoring Our Proposal Comment: We received many letters in support of our rulemaking from members representing various organizations that were similar in content and format, and are represented by two types of positive comment letters in the docket for this rulemaking. Each of these comment letters supports our proposed decision for the six coal units identified above. More than 500 of these letters specifically urge us to require emissions reductions from these six units in our final decision. We received two letters from Federal Land Managers in support of this rulemaking. These comments include support for our proposed disapproval of the Long Term Strategy under Section 51.308(d)(3) and our proposed disapproval of the Greater Reasonable Progress Alternative Determination (section 51.308), as well as support for our proposed FIP requiring an emissions limitation of 0.06 lb of SO2/MMBtu for each of the six units identified above. These comments also include agreement that EPA’’s proposed controls are cost-effective, reasonable and attainable, and that they constitute BART. These letters also included support for requiring compliance with the proposed emission limitations within three years from the effective date of the final rule, but could accept compliance within five years. At the Public Hearing in Oklahoma City, positive comments were received from representatives of a natural gas producer and from public citizens. Some App. 75 comments included support for our proposed disapproval of the Oklahoma SIP submittal, as well as for finalizing our proposed FIP. Included with these comments was the belief expressed that not controlling these sources will not make electricity cheap. Another idea presented at this hearing was that, whereas cheap electricity does not make an economy healthy, renewable energy does. Data for eight states was presented, including Washington State in which 75 percent of the electricity comes from renewable resources. Other comments were that clean air is a basic necessity of life and not a luxury, and that clean air is not something that should be traded or bargained away in the name of profit. Further, these comments included encouragement for the shortest possible timeline for compliance. Comments were also received in support of our proposal at the Public Hearing in Tulsa. One commenter noted that in the background for the proposed FIP, we accepted almost all of the methodologies and conclusions put forth by the ODEQ, with the exception of BART for SO2 removal. Another commenter mentioned that the concept of being a good neighbor and reducing air pollution is a critical component of the CAA. Response: We acknowledge these commenters for their support of this action. We also note that several of the specific emissions and timeframe limitations supported by these commenters in the proposal have been modified in this final action based on all of the information received during the comment period. Please see the docket associated with this action for additional detail. Additionally, some of the specific App. 76 issues that these commenters raised are addressed elsewhere in this notice. B. Comments Generally Against Our Proposal We received written comments, as well as oral comments at the Public Hearings in Oklahoma City and Tulsa, that generally did not support our proposed rulemaking. Most of these commenters expressed concerns about the economic impact of this rulemaking. Due to the specific nature of these comments, we address them more fully in the remainder of this notice and in the Supplemental RTC. The full text of these comments is included in the docket associated with this action. We also received one unspecific negative comment from an individual, which did not include documentation, rationale, or data for us to respond to beyond our responses provided elsewhere in this notice. C. Comments on Legal Issues 1. General Legal Comments Comment: We received several comment letters questioning whether we have CAA authority to disapprove Oklahoma’’s BART determination and determine BART through a FIP. These commenters included the Oklahoma Attorney General, OG&E, several industry trade organizations, and AEP/ PSO. We also received a comment letter signed by multiple attorneys general from throughout the United States.3 3 The signatories of this May 2011 comment letter were the attorney generals of Oklahoma, Alabama, Kentucky, Maine, the N. Mariana Islands, South Carolina, Texas, and Utah. App. 77 The commenters generally contend that our proposal would ““usurp”” or encroach on the state’’s authority and that EPA lacks the authority to substitute its own judgment or policy preferences for the state’’s determinations. The Oklahoma Attorney General comments that our role is ““simply one of support”” and that state determinations are entitled to ““special deference.”” Similarly, one commenter states that we cannot ““second-guess”” the state and redo a BART analysis with no deference to the state’’s findings. That commenter also states that we have not articulated any standard under which we may judge the validity of a state’’s BART determination. Response: Congress crafted the CAA to provide for states to take the lead in developing implementation plans, but balanced that decision by requiring EPA to review the plans to determine whether a SIP meets the requirements of the CAA. EPA’’s review of SIPs is not limited to a ministerial type of ““rubber-stamping”” of a state’’s decisions. EPA must consider not only whether the state considered the appropriate factors but acted reasonably in doing so. In undertaking such a review, EPA does not ““usurp”” the state’’s authority but ensures that such authority is reasonably exercised. EPA has the authority to issue a FIP either when EPA has made a finding that the state has failed to timely submit a SIP or where EPA has found a SIP deficient. Here, EPA has authority and we have chosen to approve as much of the Oklahoma SIP as possible and to adopt a FIP only to fill the remaining gap. Our action today is consistent with the statute. In finalizing our proposed determinations, we are approving the state’’s determinations in identifying BART eligible sources and largely approving the state’’s BART determinations App. 78 for thirteen different emission units subject to BART. We are, however, disapproving the state’’s SO2 BART determinations for six of those units. As explained in the proposal, the state’’s SO2 BART determinations for the six OG&E and AEP/PSO units are not approvable because ODEQ ““did not properly follow the requirements of section 51.308(e)(1)(ii)(A).”” 76 FR 16168, at 16182. Specifically, ODEQ did not properly ““take into consideration the costs of compliance,”” when it relied on cost estimates that greatly overestimated the costs of controls. We have determined that the faults in ODEQ’’s cost methodology were significant enough that they resulted in BART determinations for SO2 that were both unreasoned and unjustified. Accordingly, those determinations that relied on significantly flawed cost estimations are not approvable. In the absence of approvable BART determinations in the SIP for SO2 for BART eligible sources in Oklahoma, we are obliged to promulgate a FIP to satisfy the CAA requirements. Likewise, in the absence of an approvable SIP that addresses the requirement that emissions from Oklahoma sources do not interfere with measures required in the SIP of any other state to protect visibility, we are obliged to promulgate a FIP to address the defect. This authority and responsibility exists under CAA section 110(c)(1). We also are required by the terms of a consent decree with WildEarth Guardians, lodged with the U.S. District Court for the Northern District of California to ensure that Oklahoma’’s CAA requirements for 110(a)(2)(D)(i)(II) are finalized by December 13, 2011. Because we have found the state’’s SIP submissions do not adequately satisfy either requirement in full and App. 79 because we have previously found that Oklahoma failed to timely submit these SIP submissions, we have not only the authority but a duty to promulgate a FIP that meets those requirements. Our action in large part approves the RH SIP submitted by Oklahoma; the disapproval of the SO2 BART determinations and imposition of the FIP is not intended to encroach on state authority. This action is only intended to ensure that CAA requirements are satisfied using our authority under the CAA. We note that Oklahoma may submit a new SIP revision addressing the issue of SO2 controls for these six units, in which case we will assess it against Clean Air Act and Regional Haze Rule requirements as a possible replacement for the FIP. Comment: Multiple commenters have cited to various CAA statutory provisions to support their contention that the State of Oklahoma has authority or ““primary authority,”” where EPA has no authority or lesser authority. On this point, commenters have cited CAA Sections 169A(b)(2)(A) and 169A(g)(2). Specifically, Section 169A(b)(2)(A) reads in part that regulations to protect visibility shall require the installation and operation of BART ““as determined by the State (or the Administrator in the case of a plan promulgated under section 7410(c) of the this title).”” Section 169A(g)(2) begins, ““in determining [BART] the State (or the Administrator in determining emissions limitations which reflect such technology) shall”” take into consideration several requisite statutory factors. The commenters place special emphasis on the references to the ““the State”” in these provisions and contend that the plain language of the statute provides that states, and not EPA, have authority to determine BART. App. 80 Response: We agree that states have authority to determine BART, but we disagree with commenters’’ assertions that EPA has no authority or lesser authority to determine BART when promulgating a FIP. As the parenthetical in section 169A(b)(2)(A) indicates, the Administrator has the authority to determine BART ““in the case of a plan promulgated under section 7510(c).”” In other words, the Administrator has explicit authority to determine BART when promulgating a FIP. In our proposal, we stated that we must consider the same factors as states when proposing a FIP to address BART. 76 FR 16168, at 16187. Our BART determination follows the factors prescribed by CAA Section 169A(g)(2). We disagree that the language of the CAA limits our authority to determine BART in the case of a FIP. Comment: Commenters who have argued that the plain language of the CAA requires that states are the primary or only BART determining authorities have also cited our preamble language from past Federal Register publications that they believe reinforces their contention. For example, several commenters cited 70 FR 39104, at 39107, which reads in part, ““the State must determine the appropriate level of BART control for each source subject to BART.”” Commenters have also cited the preamble to our proposal, where we wrote, ““States are free to determine the weight and significance to be assigned to each factor”” when making BART determinations. 76 FR 16168, at 16174. Finally, some commenters have stated the preamble of the RHR supports their contentions when it states: ““In some cases, the State may determine that a source has already installed sufficiently stringent emission controls for compliance with other programs (e.g., the App. 81 acid rain program) such that no additional controls would be needed for compliance with the BART requirement.”” 64 FR 35714, at 35740. Response: We agree that states are assigned statutory and regulatory authority to determine BART and that many past EPA statements have confirmed state authority in this regard. Although the states have the freedom to determine the weight and significance of the statutory factors, they have an overriding obligation to come to a reasoned determination. As detailed in our proposal and the supporting Technical Support Document (TSD), the state’’s SO2 BART determinations for the six OG&E and AEP/PSO units were premised on flawed cost assumptions. Since these SO2 BART determinations of the state are not approvable, we are obliged to step into the shoes of the state and arrive at our BART determinations. Comment: Commenters have also cited other CAA provisions. One commenter states that 169A(b) only allows for EPA to issue guidelines with technical and procedural guidance for determining BART, not to issue rules that dictate the outcome (except for fossilfueled power plants with capacity that exceeds 750 MW). That commenter also contends that our lack of authority relative to the states is shown through CAA Section 169A(f), which provides that the meeting of the national visibility goal is not a ““nondiscretionary duty”” of the Administrator. AEP/PSO comments that the provisions of CAA Section 169B shows that states have special authority to act together through visibility transport commissions. The Oklahoma Attorney General cites CAA Section 101(a)(3), which provides App. 82 that air pollution control at its source ““is the primary responsibility of States and local governments.”” Response: States shoulder significant responsibilities in CAA implementation and in effectuating the requirements of the RHR. EPA has the responsibility of ensuring that state plans, including RH SIPs, conform to CAA requirements. None of the CAA provisions cited by commenters change our conclusion that we have authority to issue a FIP to satisfy BART requirements given that Oklahoma’’s RH SIP is not fully approvable. We cannot approve a RH SIP that fails to address BART with a reasoned consideration of the costs of compliance. Our inability to approve the state’’s BART determinations for SO2 means we must follow through on our nondiscretionary duty to promulgate a FIP. Under the CAA, we were required to do this by January 2011, two years after EPA found that Oklahoma failed to submit a RH SIP. 74 FR 2392. The language of CAA Section 169A(f), which concerns the meeting of the national goal, is not related to the review of a state’’s BART determinations or our determinations on their adequacy or the timing of our action. Comment: Many commenters expressed the view that their statutory arguments are reinforced by legislative history of the 1977 CAA amendments. Several commenters refer to statements of Senator Edmund Muskie regarding the conference agreement on the provisions for visibility protection in those amendments. Senator Muskie had stated that under the conference agreement the state, ““not the Administrator,”” identifies BART eligible sources and determines BART. 123 Cong. Rec. 26854 (August 4, App. 83 1977). Commenters have also noted that Am. Corn Growers Ass’’n v. EPA, 291 F.3d 1 (D.C. Cir. 2002) used legislative history, including the Conference Report on the 1977 amendments, when the Court had invalidated past regulatory provisions regarding BART for constraining state authority. The Court stated that the Conference report confirmed that Congress ““intended the states to decide which sources impair visibility and what BART controls apply to those sources.”” Response: We agree that the CAA places the requirements for determining BART for BART-eligible sources on states. As discussed above, the CAA also requires the Administrator to determine BART in the absence of an approvable determination from the state. Because we have determined that Oklahoma’’s BART determinations for SO2 for the six OG&E and AEP/PSO units do not conform with section 51.308(e) and are not approvable, we are authorized and at this time required to promulgate a FIP. Comment: Several commenters have asserted our proposal is inconsistent with the decision of the DC Circuit in Am. Corn Growers Ass’’n v. EPA, 291 F.3d 1 (D.C. Cir. 2002). They contend that language in the decision affirms their views regarding state authority and EPA’’s lack of authority in regulating the problem of regional haze. In particular, the American Corn Growers decision had described states as playing ““the lead role”” in designing and implementing regional haze programs, Id. at 3, and described the CAA as ““giving the states broad authority over BART determinations.”” Id. at 8. Response: We disagree that our proposal is inconsistent with the American Corn Growers decision. App. 84 We have determined that Oklahoma utilized flawed cost assessments and incorrectly estimated the visibility impacts of controls. We have determined these issues resulted in non-approvable SO2 BART determinations for the six OG&E and AEP/PSO units. We recognize the state’’s broad authority over BART determinations, and recognize the state’’s authority to attribute weight and significance to the statutory factors in making BART determinations. As a separate matter, however, a state’’s BART determination must be reasoned and based on an adequate record. Although we have largely approved the state’’s RH SIP, we cannot agree that CAA requirements are satisfied with respect to these SO2 BART determinations. Comment: One commenter contends that states have broader authority for regional haze, because it is not a human health-based regulation. Another commenter similarly suggests that states are the ““appropriate decision makers”” because regional haze is about haze, not health. Response: We do not agree that the CAA or RHR prescribes a different degree of authority to states based on the program having the goal of improving visibility as opposed to preventing adverse human health effects. Among other things, the CAA requires states to submit plans that satisfy NAAQS standards set to protect both public health and welfare. Nothing in the terms of the CAA or its implementation history directs that SIP submittals addressing visibility are subject to a different standard of evaluation than SIP submittals that directly address public health issues associated with air pollutants. The distinction is not pertinent to state authority to develop RH SIPs and App. 85 does not diminish our responsibility and authority to require that they conform to the RHR. Comment: Several commenters have more generally asserted that we lack authority to disapprove the RH SIP, because of past cases where we have lacked authority in particular SIP disapproval actions. These commenters have cited, in particular to Florida Power & Light Co. v. Costle, 650 F.2d 579, 581 (5th Cir. 1981) (EPA must approve a SIP that ““meets statutory criteria””), Train v. NRDC, 421 U.S. 60, 79 (1975), and Commonwealth of Vir. v. EPA, 108 F.3d 1397 (D.C. Cir. 1997). Under these cases, the commenters assert that we cannot question the wisdom of a state’’s choices or require particular control measures if plan provisions satisfy CAA standards. Response: States are required by the CAA to address the BART requirements in their SIP. Our disapproval of the SO2 BART determinations in the Oklahoma RH SIP is authorized under the CAA because the state’’s SO2 BART determinations for the six OG&E and AEP/PSO units do not satisfy the statutory criteria. The state’’s analysis of the cost effectiveness of controls was flawed due to reasons discussed elsewhere in this notice. While states have authority to exercise different choices in determining BART, the determinations must be reasonably supported. Oklahoma’’s errors in taking into consideration the costs of compliance were significant enough that we cannot conclude the state determined BART according to CAA standards. The cases cited by the commenters stress important limits on EPA authority in reviewing SIP submissions, but our disapproval of these SO2 BART determinations for the App. 86 six units has an appropriate basis in our CAA authority. Comment: A citizen commenter asserts that our proposal is indicative of ““raw unconstitutional power.”” Response: The commenter has cited no specific provisions of the Constitution. In any case, we regard neither the RHR, which has previously been subject to review by the D.C. Circuit, nor our underlying statutory authority for this action to be unconstitutional. We are acting under statutory responsibilities established in the 1977 and 1990 amendments to the CAA. As is the case for any executive agency under the authority of the President, the Constitution has charged us with the implementation and enforcement of laws written by Congress. The administration of the CAA and implementation of the RHR is accordingly not unconstitutional. Comment: AEP/PSO and another commenter have commented that our proposed action improperly combines matters under Oklahoma’’s RH SIP with unrelated matters addressed in the 2007 Interstate Transport SIP. Both commenters have stated that our disapproval of the Interstate Transport SIP would be inconsistent with our guidance in 2006. They contend our 2006 guidance had suggested conclusions regarding whether emissions from any one state could interfere with measures of neighboring states to protect visibility could only be reached when a neighboring state’’s RH SIP had been approved. These commenters believe Oklahoma’’s Interstate Transport SIP obligations under CAA Section 110(a)(2)(D)(i)(II) can be approved because there were no EPA-approved regional haze App. 87 SIPs at the time of submittal or when we reviewed the Oklahoma submission. Response: We disagree with contention of the commenters that RH SIP requirements and the visibility requirements of section 110(a)(2)(D)(i)(II) are unrelated. We are addressing them simultaneously because the purposes and requirements of the interstate transport provisions of the CAA with respect to visibility and the RH program are intertwined. Section 110(a)(2)(D)(i)(II) does not explicitly define what is required in SIPs to prevent the prohibited impact on visibility in other states. However, because the RH program requires measures that must be included in SIPs specifically to protect visibility, EPA’’s 2006 Guidance4 recommended that RH SIP submissions meeting the requirements of the visibility program could satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with respect to visibility. Subsequently, in instances in which some states did not make the RH SIP submission, in whole or in part, or did not make an approvable RH SIP submission, we evaluated whether those states could comply with section 110(a)(2)(D)(i)(II) by other means. Thus, we have elsewhere determined that states may also be able to satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with something less than an approved RH SIP, see, for example, our determinations 4 See, ““Guidance for State Implementation Plan (SIP) Submissions to Meet Current Outstanding Obligations Under Section 110(a)(2)(D)(i) for the 8-Hour Ozone and PM2.5 National Ambient Air Quality Standards,”” from William T. Harnett, Director Air Quality Policy Division, OAQPS, to Regional Air Division Director, Regions I––X, dated August 15, 2006 (the ““2006 Guidance””). App. 88 regarding Colorado (76 FR 22036) and Idaho (76 FR 36329). In other words, an approved RH SIP is not the only possible means to satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with respect to visibility; however, such a SIP could be sufficient. Given this reasoning, we do not agree with commenters’’ contentions that our action improperly combines two unrelated programs. Regarding our guidance on submissions in August of 2006, we explicitly stated that ““at this point in time,”” it was not possible to assess whether emissions from sources in the state would interfere with measures in the SIPs of other states. As subsequent events have demonstrated, we were mistaken as to the assumption that all states would submit RH SIPs in December of 2007, as required by the RHR, and mistaken as to the assumption that all such submissions would meet applicable RH program requirements and therefore be approved shortly thereafter. Thus the premise of the 2006 Guidance that it would be appropriate to await submission and approval of such RH SIPs before evaluating SIPs for compliance with section 110(a)(2)(D)(i)(II) was in error. Our 2006 Guidance was clearly intended to make recommendations that were relevant at that point in time, and subsequent events have rendered it inappropriate in this specific action. We must therefore act upon Oklahoma’’s submission in light of the actual facts, and in light of the statutory requirements of section 110(a)(2)(D)(i). In order to evaluate whether the state’’s SIP currently in fact contains provisions sufficient to prevent the prohibited impacts on the required programs of other states, we are obligated to consider the current circumstances and investigate the level of controls at Oklahoma sources App. 89 and whether those controls are or are not sufficient to prevent such impacts. We reject the argument that Oklahoma’’s submittal should be approvable because surrounding states have yet to submit RH SIPs that have been approved. The argument fails to address what would happen if a downwind state were never to submit the required RH SIP, or were never to submit a RH SIP that was approvable. On its face, the commenter’’s argument is simply inconsistent with the objectives of the statute to protect visibility programs in other states if a state never submits an approvable RH SIP. Second, this approach is flatly inconsistent with the timing requirements of section 110(a)(1) which specifies that SIP submissions to address section 110(a)(2)(D)(i), including the visibility prong of that section, must be made within three years after the promulgation of a new or revised NAAQS. We acknowledge that there have been delays with both RH SIP submissions by states and our actions on those RH SIP submissions, but that fact does not support a reading of the statute that overrides the timing requirements of the statute. At this point in time, states are required to have submitted regional haze plans to EPA that establish reasonable progress goals for Class I areas. This requirement applies whether or not states have in fact submitted such plans. We believe that there are means available now to evaluate whether a state’’s section 110(a)(2)(d)(i)(II) SIP submission meets the substantive requirement that it contain provisions to prohibit interference with the visibility programs of other states, and therefore that further delay, until all RH SIPs are submitted and fully approved, is unwarranted App. 90 and inconsistent with the key objective to protect visibility. As detailed in our proposal, we believe based on the information currently before us that an implementation plan that provides for emissions reductions consistent with the assumptions used in the modeling of other CENRAP states will ensure that emissions from Oklahoma sources do not interfere with the measures designed to protect visibility in other states. 76 FR 16168, at 16193. The Oklahoma SO2 BART determinations for the six OG&E and AEP/PSO units did not require these sources to meet the level of control assumed in the CENRAP modeling. As we discuss elsewhere in our response to comments, Oklahoma engaged in a regional planning process. This regional planning process included a forum in which state representatives built emission inventories that assumed that specific pollution sources would be controlled to specific levels. This included assumptions that the six OG&E and AEP/PSO units would be controlled to presumptive BART emission levels for SO2. Visibility modeling projections subsequently assumed those emission reductions, and other states relied on those reductions as part of their reasonable progress demonstrations. Accordingly and consistent with our proposal, we are partially disapproving the Oklahoma SIP revision submitted to address the requirements of CAA section 110(a)(2)(D)(i)(II). The FIP remedies the inadequacy in the Oklahoma SIP by requiring controls for the six units that at least achieve the level of control assumed in the CENRAP modeling. Comment: AEP/PSO and another commenter have asserted that the promulgation of revised NAAQS for App. 91 ozone and PM2.5 in 1997 did not trigger any additional SIP obligations with respect to section 110(a)(2)(D)(i)(II). A commenter believes that these revised NAAQS are not meaningfully related to visibility requirements in Title I Part C, of the CAA. The commenters ask EPA to determine that no obligation to address Part C visibility components of a SIP arose from those NAAQS revisions. Response: Reduced visibility is an effect of air pollution, and the emissions of PM2.5 and ozone and its precursors can contribute to visibility impairment. SIP planning for the control of these pollutants on the promulgation of a new NAAQS will therefore implicate control measures and issues relating to visibility. CAA section 110(a)(1) therefore requires implementation plans submitted in the wake of a newly promulgated NAAQS to address whether the state has adequate provisions to prevent interference with the efforts of other states to protect visibility. The obligation to address Part C visibility components expressly follows from the language of 110(a) concerning when plans must be submitted and what each implementation plan must contain. Comment: OG&E contends that EPA’’s proposal to disapprove the state’’s BART determination is faulty, because the agency relied ““without critical review”” on what the commenter describes as the ““opinion”” of a contracted consultant. The commenter contends EPA’’s our consultant is unqualified to evaluate costs of installing and operating scrubbers at the OG&E Units, because our consultant ““has no experience designing scrubbers or estimating their costs.”” Additionally, OG&E states our consultant lacked relevant knowledge App. 92 about the OG&E Units and the facilities at which these units are located, and did not attempt to communicate with OG&E or its contractor about the particular design parameters, engineering specifications, or other intricacies associated with the OG&E units. The commenter believes the consultant’’s report contains opinions that ““lack adequate foundation.”” On this basis, OG&E states that EPA cannot lawfully rely on the consultant’’s report. Response: As an initial matter, we do not agree that our regulatory actions are subject to evidentiary rules regarding expert testimony, as this comment suggests. Our consultant’’s detailed report was incorporated as technical support for our regulatory determinations and is not properly characterized as an opinion. The contention that we accepted the consultant’’s report without critical review is false. As was stated in our proposal, only after we thoroughly reviewed and evaluated the report was it made a part of our TSD. 76 FR 16168, at 16182––16183. Furthermore, we met with OG&E and its consultant concerning the development of our proposal and had extensive communications clarifying particular technical points. This information was coordinated with our consultant and was incorporated into her report. Thus, we worked closely with our consultant in the development of her report. Comment: A commenter states that EPA’’s proposed BART determination would violate Executive Order 13132, Federalism. Response: We do not agree that our proposal or this final action violates Executive Order 13132. EPA is taking actions specified under the CAA in partially approving and partially disapproving the Oklahoma App. 93 RH SIP. The CAA also specifies the responsibility of EPA to issue a FIP when states have not met their requirements under the CAA. EPA is promulgating this FIP to fill the regulatory gap created by the partial disapproval. Under the FIP, the state retains its authority to submit future RH SIPs consistent with CAA and RHR requirements; we do not discount the possibility of a future, approvable RH SIP submission that results in the modification or withdrawal of the FIP. This rulemaking does not change the distribution of power between the states and EPA. Consistent with this, in the Executive Orders section of this rulemaking, we have determined that Executive Order 13132 does not apply to this action. Comment: A commenter states that EPA cannot propose a FIP until after it has taken final action to disapprove a state implementation plan. The commenter cites to part of CAA section 110(c)(1) which states that the Administrator shall promulgate a FIP ““at any time within 2 years after”” the Administrator ““disapproves a State implementation plan submission.”” The commenter states that EPA should withdraw the proposed FIP, take final action only on the SIP, and only then propose a FIP, if one is necessary. Response: We have the authority to promulgate a FIP concurrently with a disapproval action. This timing for FIP promulgation is authorized under CAA section 110(c)(1). As has been noted in past FIP promulgation actions, the language of CAA section 110(c)(1), by its terms, establishes a two-year period within which we must promulgate the FIP, and provides no further constraints on timing. See, e.g., 76 FR 25178, at 25202. Oklahoma failed to submit its regional haze SIP to us App. 94 by December 2007, as required by Congress. Two years later, Oklahoma had still not submitted its regional haze SIP. When we made a finding in 2009 that Oklahoma had failed to submit its regional haze SIP, (see 74 FR 2392), that created an obligation for us to promulgate a FIP by January 2011. We are exercising our discretion to promulgate the FIP concurrently with our disapproval action because of the applicable statutory deadlines requiring us at this time to promulgate RH BART determinations to the extent Oklahoma’’s BART determinations are not approvable. Comment: OG&E expresses the view that we have improperly combined a proposed disapproval of the Oklahoma SIP with our own BART determination. The commenter contends that the fact we would reach a different BART determination is not ““itself sufficient grounds to disapprove the SIP.”” The commenter believes EPA desired to have scrubbers installed on the OG&E units and is only proposing to substitute its own BART determination ““to mask the fact that it lacks any meritorious grounds to disapprove ODEQ’’s BART determination.”” Response: Our grounds for disapproving ODEQ’’s SO2 BART determination were articulated in our proposal, and we have not claimed that having arrived at a different SO2 BART determination constitutes a basis for disapproval. Instead, as was clear in our proposal, we were obliged to develop an SO2 BART determination because Oklahoma’’s SO2 BART determination was flawed and not approvable. The fact that Oklahoma’’s SO2 BART determination was not approvable caused us to develop a BART determination App. 95 that adheres to 51.308(e)(1)(ii)(A). the requirements of section Comment: OG&E comments that we cannot justify our disapproval based on aggregate visibility improvements. The commenter asserts that when we review a SIP or propose a FIP, the agency is required to consider the visibility improvement associated with scrubbers on a facility-by-facility basis. The commenter points to a portion of our proposal where we stated that modeling demonstrates a ““2.89 deciview improvement in visibility,”” 76 FR 16168, at 16186, and notes the statement is based on combining impacts from scrubbers at multiple units. The commenter asserts this approach violates the individual facility approach dictated by CAA as outlined in the American Corn Growers case and violates the RHR and the guidelines that responded to that case outcome. In particular, the commenter cites to the preamble language at 70 FR 39104, at 39106 which describes how the RHR was amended ““to require the States to consider the degree of visibility improvement resulting from a source’’s installation and operation of retrofit technology, along with the other statutory factors.”” The commenter attributes significance to EPA’’s phrasing, which had stated in part, ““* * * States will be required to consider all five factors, including visibility impacts, on an individual source basis when making each individual source BART determination.”” Another commenter also contends we based our SO2 BART proposal for the six OG&E and AEP/PSO units on a visibility estimate of an 8.20 dv cumulative improvement over multiple Class I areas. Further, this commenter contends we have claimed this visibility App. 96 improvement will result from emission reductions at all three facilities combined, which the commenter characterizes as a form of aggregation that is impermissible, as BART must be determined on a source-by-source basis. The commenter also stated that analysis should be focused on the visibility impacts at the most impacted area, not all areas. The commenter claims our rules indicate that it is appropriate to model impacts at the nearest Class I area as well as impacts at other nearby Class I areas. However, in the case of the latter category of areas, merely for the purpose of ““determin[ing] whether effects at those [other] areas may be greater than at the nearest Class I area.”” 70 FR 39104, at 39170. Further, continues the commenter, the rules state that ““[i]f the highest modeled effects are observed at the nearest Class I area, you may choose not to analyze the other Class I areas any further * * *.”” Id. Based on this, the commenter states that that the BART rules contemplate a visibility improvement analysis that only is focused on visibility impacts in the most impacted area, not all areas. Response: We proposed disapproval of the Oklahoma SO2 BART determination for the six OG&E and AEP/PSO units in part because we disagreed with ODEQ’’s cost analysis, and our own visibility modeling indicated SO2 controls would result in significant visibility improvement. In so doing, we adhered to the requirements of section 51.308(e). Oklahoma’’s SO2 BART determinations for the six units were based on flawed costing methodologies. Our determinations regarding visibility improvement are not inconsistent with the CAA or the court’’s interpretation in American Corn Growers of the individual facility approach that must be utilized when making BART determinations. App. 97 Although we noted in the proposal the combined visibility improvement at four Class I areas due to the installation of SO2 controls at the six OG&E and AEP/PSO units, our FIP is not based on an analysis of visibility improvements that are aggregated across multiple facilities. Rather, we assessed the visibility improvement of each facility separately. Our visibility modeling shows that the six OG&E and AEP/PSO units ““causes or contributes”” to visibility impairment——as the phrase is defined in the RHR5——at four Class I areas. As Table 1 indicates, the number of days per year each Class I area is impacted at this level by each facility’’s emissions are expected to decrease drastically at each Class I area as the result of installation of SO2 BART emission controls at the six units. Clearly, the visibility benefits from SO2 BART emission reductions will be spread among all affected Class I areas, not only the most affected area, and should be considered in evaluation of benefits from proposed reductions. The portion of the BART Guidelines (40 CFR 51 Appendix Y, IV.D.5) that the commenter referenced states: ““If the highest modeled effects are observed at the nearest Class I area, you may choose not to analyze the other Class I areas any further as additional analyses might be unwarranted.”” This section of the BART Guidelines addresses how to determine visibility impacts as part of the BART determination and is intended to make clear that if certain controls would be justified based on the impacts at the nearest Class I area, the state is not required to 5 States should consider a 1.0 deciview change or more from an individual source to ““cause”” visibility impairment, and a change of 0.5 deciviews to ““contribute”” to impairment. 70 FR 39120. App. 98 undertake an exhaustive analysis of impacts across multiple Class I areas. Several paragraphs later in the BART Guidelines is the following: ““You have flexibility to assess visibility improvements due to BART controls by one or more methods. You may consider the frequency, magnitude, and duration components of impairment,”” emphasizing the flexibility in method and metrics that exists in assessing the net visibility improvement. Comment: OG&E comments that we had improperly analyzed the ““contingent BART determination that applies if EPA rejects ODEQ’’s determination that low sulfur coal is BART and all appeals are exhausted.”” The commenter says the contingent BART determination should not have been analyzed as a BART alternative under 40 CFR 51.308, because it is ““not a BART alternative.”” If the contingent determination were to be effectuated, the commenter asserts that scrubbers would then constitute BART itself, not an alternative to BART scrutinized under separate rules. The commenter also asserts that the contingent BART finding would be consistent with the statutory timeframe for installation of BART (viz., ““in no event later than five years”” under CAA section 169A(g)(4)), because the contingent BART finding would not be triggered until the appellate process had concluded and because a final appellate ruling might be made before 2013, which could result in a time for compliance that is shorter than five years. Response: The RHR does not afford the option of submitting contingent BART determinations that would apply and become effective when EPA disapproves and successfully defends its disapproval of App. 99 a state’’s BART determination. This item in the RH SIP could not be evaluated as a BART determination, because it is not on its face a BART finding. This component of the RH SIP submission inherently speculates on the actions and outcomes of review by EPA and the courts, and is contrary to the SIP planning and review expected under the RHR and the CAA, more generally. Accordingly, we properly evaluated these provisions as an alternative to BART and determined that the contingent BART determination was not approvable under 40 CFR 51.308. We disagree that it could be reviewed under any other provision and found to be consistent with the RHR. Comment: OG&E comments that we had improperly analyzed the ““2026 compliance option”” as failing to meet the standards of a BART alternative. In the commenter’’s view, the 2026 compliance is not a BART alternative but only a measure ““to implement a longterm strategy in the name of reasonable progress.”” OG&E asserts that ODEQ has authority for this under 51.308(d)(3), and that implementation of the compliance option could reduce emissions more than would be possible with dry scrubbers, and that our evaluation of the 2026 compliance option loses sight of the long-term national goal. Response: We disagree that the contingent SIP provision can be recognized as implementing a longterm strategy. As discussed in our response regarding the ““contingent BART determination,”” this component of the RH SIP is not on its face reviewable as a BART determination and fails to satisfy the requirements of Section 51.308. The contingent SIP is predicated on App. 100 speculative actions and outcomes of review by EPA and courts, and does not comport with established SIP planning and approval processes under the CAA. Comment: A commenter expressed concern that EPA has ignored the regional haze plan supported by ODEQ and local utilities, and states, ““EPA has assumed the State’’s role under the Clean Air Act and has simply chosen not to exercise its discretion to approve the Greater Reasonable Progress Alternative Determination.”” Another commenter also submitted a comment requesting that EPA use the Oklahoma RH SIP as a guideline in the decision making process. Another commenter from the office of Oklahoma’’s Attorney General states that we ““should defer to the state plan,”” because Oklahoma is in a superior position to make decisions regarding energy policy. Response: We note that our action today largely approves the regional haze plan submitted by Oklahoma. We are, however, finalizing disapprovals of the state’’s SO2 BART determinations and the ““Greater Reasonable Progress Alternative Determination”” referenced by the commenter. We have determined that neither of these components of the RH SIP submission conforms to CAA and RHR requirements. Because Oklahoma’’s SO2 BART determinations are not being approved, we have promulgated a FIP that determines SO2 BART for the six OG&E and AEP/PSO units in a manner consistent with RHR requirements. We agree that this action, as with any FIP, may be said to assume a planning role ordinarily belonging to the state. Even with the finalization of the FIP, the state nevertheless retains its authority to submit future RH SIPs consistent with CAA and RHR requirements; we App. 101 do not discount the possibility of a future, approvable RH SIP submission that results in the modification or withdrawal of the FIP. In the meantime, sources must comply with the requirements of the FIP and the approved components of Oklahoma’’s RH SIP. 2. Comments Asking EPA To Consider All Rules Comment: OG&E comments that installation of scrubbers will consume a significant amount of additional power that would need to be generated by burning additional fuel. The commenter suggests that increased GHG emissions from the additional fuel combustion could trigger the requirement to obtain a prevention of significant deterioration (PSD) permit for greenhouse gas emissions (GHGs). The commenter asserts that a PSD permit application process ““can take 18––24 months”” and, if the process is necessary, it might be impossible to accommodate any PSD permit application process in a three-year compliance period. The commenter further contends the permitting process will impose costs and the terms of the PSD permit might impose costs if changes to the method of operation or additional control technologies are required. The commenter says we failed to account for these costs in our cost evaluation. Response: We agree that the installation of SO2 dry scrubbers at the six OG&E and AEP/PSO units could conceivably increase the emissions of other regulated new source review pollutants, including GHGs, to the point where PSD review is triggered. Any PSD permit that is necessary would have to be obtained from ODEQ, which is the permitting authority in Oklahoma. Whether or not PSD permitting is required would be based on design-specific considerations and App. 102 applicability determinations that will vary with each unit. OG&E has not provided underlying data or facts to substantiate first, that PSD permitting could not be avoided through controls designed to consume less power, and second that a PSD permit, if needed, would impose additional or collateral costs that would materially change our cost evaluation. We also disagree with the assertion that PSD permitting will require 18––24 months; Oklahoma’’s SIP for PSD permitting, consistent with CAA section 165(c), establishes a one year objective for granting or denying PSD permit applications. As we discuss elsewhere in this notice and in our Supplemental RTC, we find that compliance with SO2 BART for the six units is extended to five years, which should provide ample opportunity to satisfy PSD permitting requirements, if any. Comment: A commenter states that the proposed three-year compliance period is not justified. The commenter contends that we should consider other regulations that we are formulating for the power sector that will affect the six units covered by the FIP. The commenter mentions the Clean Air Transport Rule, the proposed Air Toxics rule, the projected NSPS, and rules for GHGs, coal combustion waste, and implementation of 316(b) of the Clean Water Act. The commenter states the compliance period is inadequate because utilities would not have sufficient time to develop a plan that addresses all of the regulations we are considering, including BART, because those rules may affect how they choose to comply with any given BART limitations. The commenter also thinks we should be required to analyze whether the compliance timeframe is appropriate by examining whether the other regulations will cause delays because of App. 103 simultaneous demands for materials, equipment, supplies, and labor. In related comments, OG&E and another commenter state that other regulatory developments that impact coal burning power plants in the period since Oklahoma submitted its SIP should be considered in our BART analysis, including the utility MACT proposal, the cooling water intake proposal, and the coal ash disposal proposal. OG&E further cites additional possible regulations through revision of the NAAQS, and the clean air transport proposal. OG&E states the control requirements and costs of these other rules should be considered in establishing the remaining useful life of the OG&E units for the BART analysis. OG&E is concerned that depending on the outcome of these rulemaking processes, some or all of the units in question may not continue to be economically viable. The Governor of Oklahoma also submitted a comment requesting EPA to consider the impact that subsequent rulemakings may have on the issue of regional haze. Response: We agree that multiple regulatory actions are pending that will affect the power sector and agree that regulatory development should be coordinated when possible. We also recognize the importance of long-term and coordinated planning on the part of owners of industrial sources that are subject to BART. The visibility requirements of the CAA were put in place in 1977 and 1990, and our implementing regulations adopted in 1999, and the regional haze requirement for installation and operation of BART, in particular, must be carried out expeditiously. We have no basis and no supporting evidence from the App. 104 commenter or any other source to conclude that significant market constraints for materials, equipment, supplies and labor would arise to make a three-year compliance period unachievable, but we do recognize the importance of planning within any compliance period. As we discuss elsewhere in this notice and in the Supplemental RTC, we have extended the compliance timeframe from the three years we proposed. Compliance with the SO2 BART emission limits in our FIP must be within five years of the effective date of our final rule, which is the maximum time permitted by statute. With regard to the BART analysis, the BART guidelines do allow for consideration of the remaining useful life of facilities when considering the costs of potential BART controls. Such a claim would have to be secured by an enforceable requirement. Neither OG&E nor AEP/PSO claimed any such restrictions on the operation of these six units. Consequently, we assumed a remaining useful life of 30 years in our BART analysis. If OG&E and/or AEP/ PSO decide the units in question have a shorter useful life such that installing scrubbers is no longer cost effective, and are willing to accept an enforceable requirement to that effect, a revised BART analysis could be submitted by the plant(s) in question and our FIP could be re-analyzed accordingly. Similarly, we could also review a revised SIP submitted by ODEQ. The RHR follows from statutory requirements of the CAA that are separate and independent from the regulatory requirements mandated by other components of the CAA and by other federal statutory schemes cited by the commenters. Even assuming the App. 105 cited regulations were finalized and costs of these regulations were non-speculative, they have no bearing on the cost effectiveness analysis used to determine BART. Whether or not SO2 BART is cost effective in conjunction with possibly unrelated environmental controls that may be separately required by other statutes such as the Clean Water Act is not part of the statutory formulation that Congress prescribed to address regional haze. 3. Comments on Interstate Transport Comment: We received two comments emphasizing that regional haze is a problem that is not always contained by state boundaries. One of the commenters states that a ““regional approach is critical”” and notes that CAA Section 169B(c)(1) authorizes the establishment of visibility transport regions. The commenter states that visibility issues for the Wichita Mountains Wilderness Area (WMWA) make it a ““candidate for consideration of the establishment of a transport region.”” The commenter believes that a regional examination or study of all the issues will allow development of the long range strategies and lead to cost-effective management of all pollution sources that impair visibility in the region’’s Class I areas. Response: We agree that pollutants from one or more states can significantly contribute to visibility impairment in the Class I areas of different states. CAA section 110(a)(2)(D)(i)(II) explicitly provides that states must have SIPs with adequate provisions to prevent interference with the efforts of other states to protect visibility. Our FIP action ensures that sources in Oklahoma meet the RH requirements for BART and the visibility requirements of section 110(a)(2)(D)(i)(II). App. 106 We also agree that a regional approach to addressing visibility transport is important, which is why EPA funded Regional Planning Organizations (RPOs), such as the Central Regional Air Planning Organization (CENRAP), in which Oklahoma participated. States such as Oklahoma engaged in the RPO process for years in order to co-develop strategies for mitigating regional haze. At this time, we do not believe that delaying or setting aside these strategies in order to further study regional haze through the formation of a transport region is appropriate. However, we note the Administrator has statutory discretion to establish a transport region in the future and may do so on the Administrator’’s own motion or on consideration of a ““petition from the Governors of at least two affected States.”” CAA Section 169B(c)(1). D. Comments on Modeling Comment: AEP/PSO stated that visibility improvements expected by installing controls under our FIP are nearly identical to the improvements from the actions included in the ODEQ SIP submission, and that the FIP controls will not provide a noticeable improvement in visibility. The commenter concludes that the actions included in the ODEQ SIP submission are just as effective in reducing visibility impairment as the FIP. We received additional comments that installation of controls proposed in the FIP would result in imperceptible or nearly imperceptible improvements in visibility. Information is provided in the comments that claims to support the statement that there is ““virtually no distinguishable”” difference between the controlled and uncontrolled cases. App. 107 Response: We performed visibility modeling as part of the SO2 BART determination analysis. A change of approximately one deciview (dv) is generally regarded as a perceptible change in visibility. 70 FR 39104, at 39118. ““For purposes of determining which sources are subject to BART, states should consider a 1.0 deciview change or more from an individual source to ‘‘cause’’ visibility impairment, and a change of 0.5 deciviews to ‘‘contribute’’ to impairment.””6 70 FR 39104, at 39120. Our modeling indicates that visibility improvements anticipated from the installation of dry scrubbers at each facility will result in reducing modeled impacts (maximum of 98th percentile daily maximum dv) from each facility at all nearby Class I areas to levels below 0.5 dv, with improvements greater than 1.0 dv at some Class I areas. We also evaluated the amount of improvement in the number of days that each facility would either cause or contribute to visibility impairment. As detailed in Table 1 below, the reductions resulting from our FIP would almost completely eliminate days when any of the three facilities’’ BART units have a perceptible impact (greater than 1.0 dv). These reductions would also significantly decrease the number of days that have a 0.5 deciview impact (or greater). 6 ““If ‘‘causing’’ visibility impairment means causing a humanly perceptible change in visibility in virtually all situations (i.e. a 1.0 deciview change), then ‘‘contributing’’ to visibility impairment must mean having some lesser impact on the conditions affecting visibility that need not rise to the level of human perception.”” 70 FR 39104, at 39120. 345 363 327 234 HerculesGlades Upper Buffalo Wichita Mountains Distance to unit (km) Caney Creek Class I area 18 2 2 3 Baseline LNB & DFGD 10 1 0 1 1 0 0 0 Sooner Units 1 & 2 LNB Average # of days/yr > 1.0 dv 38 11 9 14 Baseline LNB 25 5 3 5 LNB & DFGD Average # of days/yr > 0.5 dv 3 0 0 0 TABLE 1——AVERAGE NUMBER OF DAYS PER YEAR EACH FACILITY’’S VISIBILITY IMPACTS EXCEED 1.0 AND 0.5 DECIVIEWS App. 108 180 230 164 324 Caney Creek HerculesGlades Upper Buffalo Wichita Mountains TOTAL Average # of days/year 12 1 12 15 7 17 7 8 5 7 0 0 0 0 Muskogee Units 4 & 5 25 26 34 22 46 72 20 25 14 28 38 2 2 1 3 3 App. 109 263 244 211 323 Caney Creek HerculesGlades Upper Buffalo Wichita Mountains TOTAL Average # of days/year 27 0 11 8 6 10 7 4 4 6 0 0 0 0 Northeastern Units 3 & 4 51 24 21 17 30 128 16 12 11 17 86 2 1 0 1 8 App. 110 App9wmest SERVE App. 112 In addition, in a situation where the installation of BART may not result in a perceptible improvement in visibility, the visibility benefit may still be significant, as explained by the preamble of the RHR: ““Failing to consider less-than-perceptible contributions to visibility impairment would ignore the CAA’’s intent to have BART requirements apply to sources that contribute to, as well as cause, such impairment.”” 70 FR 39104, at 39129. Given that sources are subject to BART based on a contribution threshold of no greater than 0.5 deciviews, it would be inconsistent to automatically rule out additional controls where the improvement in visibility may be less than 1.0 deciview or even 0.5 deciviews. A perceptible visibility improvement is not a requirement of the BART determination because visibility improvements that are not perceptible may still be determined to be significant. We considered the reduction in visibility impairment at Wichita Mountains, Caney Creek, Upper Buffalo, and HerculesGlades to be significant. Installation of dry scrubbers at each facility will result in significant visibility improvements, reducing the number of days with impaired visibility due to each of these sources at all impacted Class I areas (Table 1). Comment: AEP/PSO stated that we should accept the visibility analysis results provided in ODEQ’’s SIP for determining BART for SO2 because the results of both our and ODEQ’’s visibility modeling are not significantly different. Response: We disagree that ODEQ’’s modeling was sufficient for evaluating the visibility impacts to inform our BART determination. Given that the emission rates that we proposed as SO2 BART differed from App. 113 those assumed in ODEQ’’s BART visibility modeling, it was necessary to perform our own CALPUFF visibility modeling. In doing so, we followed EPA/FLM guidance and practices to assess the anticipated visibility improvements from the use of dry and wet scrubbers with emission rates of 0.06 and 0.04 lb of SO2/MMBtu, respectively. ODEQ, in contrast, used emission rates of 0.10 and 0.08 lb of SO2/MMBtu for dry and wet scrubbers, respectively, in its modeling. As a result, ODEQ underestimated the visibility improvements associated with the use of dry and wet scrubbers. Furthermore, ODEQ’’s BART visibility analyses relied on pollutant-specific modeling to evaluate the visibility benefits from the use of available SO2 emission controls. As discussed in the TSD that accompanied the proposed action and elsewhere in our response to comments, due to the complexity of atmospheric chemistry and chemical transformation among pollutants, we modeled all visibility impairing pollutants together to fully assess the visibility improvement anticipated from the use of controls. As detailed in the TSD, we also had updated emission estimates for sulfuric acid emissions based on the latest information, and corrected PM speciation that was included in our modeling. We therefore disagree with the commenter and have explained why we needed to do our own BART CALPUFF visibility analysis. We modeled the emission rates determined to be achievable by the available and technologically feasible controls in accordance with the appropriate procedures, utilizing current practices and model versions that were acceptable to us at the time they were conducted in the latter half of 2010, and we are confident in using our results as one of the five factors in making a BART determination. App. 114 Comment: A commenter stated that in our visibility analysis, we updated the PM speciation analysis for both Sooner and Muskogee to use National Park Service (NPS) speciation profiles for dry bottom boilers rather than wet bottom boilers calculated in ODEQ’’s SIP submission and used updated coal properties. The commenter concludes that the difference between ODEQ’’s PM speciation and EPA’’s should not impact the BART analysis because primary PM species emitted directly from the stack generally have little overall impact on visibility impairment, and PM specific controls are not being considered for BART. In addition, the commenter states that we used different estimates for sulfuric acid emissions used to represent emissions of sulfate particles. The commenter states that this sulfate emission rate is not likely to be a significant factor in the overall visibility impairment and therefore the differences between ODEQ’’s modeling and EPA’’s modeling is not significant. Because the results are not significantly different between EPA’’s and ODEQ’’s visibility modeling, the commenter asserts that we have no basis for not accepting the visibility modeling provided in the SIP. Response: As discussed in the TSD, it was necessary for us to perform CALPUFF visibility modeling to assess the anticipated visibility improvements from the use of dry and wet scrubbers at the achievable SO2 emission rates of 0.06 and 0.04 lbs/MMBtu, respectively. Because revised modeling was necessary to support our proposed BART determination, we performed modeling following EPA/FLM guidance and practices, and corrected errors noted during our review of ODEQ’’s modeling. Our modeling included revised PM speciation to correct errors in PM speciation that App. 115 was included in ODEQ’’s modeling. As detailed in the TSD, ODEQ used incorrect coal properties and emission factors in calculating the PM speciation used in their modeling. In addition, we estimated sulfuric acid emissions using the best current information available from the Electric Power Research Institute (EPRI)7 and the correct coal properties. ODEQ estimates of sulfuric acid emissions for Sooner and Muskogee failed to account for removal in the existing air heater or ESP. ODEQ’’s estimates of sulfuric acid emissions from the Northeastern units were based on an assumption of 3 ppm sulfur content conversion in the flue gas. Furthermore, sulfuric acid emission estimates used in ODEQ’’s PM pollutant-specific modeling were based on the erroneous PM speciation discussed above. We agree with the commenter that primary PM and sulfuric acid emissions from the sources modeled may not significantly impact visibility. However, in performing our own modeling analysis to support our BART determination, we saw no reason to not make corrections and estimate emissions based on accepted methodology using the best current information, correct emission factors and coal properties. Because emissions of PM and sulfuric acid vary between wet and dry scrubbers and do have some impact on visibility conditions, we utilized the best estimates for the emissions of these species to fully account for the difference in visibility impacts between the base case and the two control cases modeled. 7 ““Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Version 2010a. EPRI, Palo Alto, CA: 2010. 1020636.”” App. 116 Comment: AEP/PSO asserted that we incorrectly rejected the ODEQ visibility improvement evaluation because ODEQ applied various controls using pollutant-specific baseline and control model runs, as opposed to using all visibility impairing pollutants in the calculation of the baseline and control model runs. The commenter states that our BART guidelines are not specific as to how to evaluate visibility improvement for the application of BART controls. The commenter asserts that the pollutant specific CALPUFF modeling approach is a reasonable but simplistic method to look at the improvement in visibility impairment attributable to NOX, SO2, or PM and is consistent with our guidance contained in a BART Q&A document that states that the control technology visibility analysis can be conducted for single units and individual pollutants. Response: The referenced BART Q&A document8 states that it may be appropriate to conduct a unit by unit, pollutant by pollutant analysis, depending on the types of units and control measures under consideration. As discussed in the TSD, due to the nonlinear nature and complexity of atmospheric chemistry and chemical transformation among pollutants, all relevant pollutants should be modeled together to predict the total visibility impact at each 8 ““Q&A’’s for Source by Source BART rule,”” dated July 6, 2005. This document is not available on EPA’’s Web site and is a draft document reflecting the preliminary views of EPA staff on a number of questions submitted by stakeholders. App. 117 Class I area receptor.9 The referenced Q&A document provides clarification and guidance on performing visibility analyses for BART. The emissions of NOX and SO2, should be modeled together to determine the visibility impacts, and in evaluation of controls and combinations of controls in determining BART for a source. As seen in our modeling results for wet and dry scrubbers included in our proposal and TSD, the chemical interaction between pollutants and background species can lead to situations where the reduction of emissions of a pollutant can actually lead to an increase in visibility impairment. Therefore, to fully assess the visibility benefit anticipated from the use of controls, all pollutants should be modeled together. As discussed elsewhere in this response to comments, it was necessary for us to perform CALPUFF visibility modeling to assess the anticipated visibility improvements from the use of dry and wet scrubbers at the achievable SO2 emission rates of 0.06 and 0.04 lb/MMBtu, respectively. Because revised modeling was necessary to support our proposed BART determination, we performed modeling following EPA/FLM guidance and practices, including modeling all visibility impairing pollutants together to fully assess the total visibility benefit anticipated from emission reductions. Comment: AEP/PSO stated that when we calculated visibility improvement during our BART analysis, we used the monthly average humidity adjustment factors 9 ““Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations,”” from Joseph Paisie, Geographic Strategies Group, OAQPS, to Kay Prince, Branch Chief, EPA Region 4, dated July 19, 2006. App. 118 provided in Table A––2 of our 2003 Guidance document for the assessment of natural background visibility, whereas, ODEQ used Table A––3 in its visibility calculations. The commenter states that there is no guidance that requires the use of humidity factors from Table A––2 as opposed to Table A––3. In addition, the commenter states that the use of humidity factors from Table A––2 instead of A––3 should not make a significant difference in the overall visibility impairment and does not provide a basis for our rejection of the visibility modeling provided in the SIP submittal. Response: EPA guidance for estimating natural visibility conditions under the RHR provides monthly site-specific relative humidity factors for use in calculating visibility impairment.10 Table A––2 of the guidance contains the ““recommended”” values based on the representative IMPROVE site location. Table A––3 provides data based on the centroid of the area as ““supplemental information.”” Relative humidity factors are used with the original IMPROVE equation to calculate extinction from measured or predicted pollutant concentrations. The factors used by ODEQ are not the recommended values and are given in the guidance document only as supplemental information. Furthermore, EPA guidance for tracking progress under the RHR contains that same information also labeled Table A––2 and A––3 and is consistent with the 10 See, ““Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule,”” EPA––454/B––03––005, September 2003. App. 119 above guidance material.11 This guidance states that the site specific values provided in Table A––2 for each mandatory federal Class I area are recommended to be used for all visibility and tracking progress calculations for that Class I area. Table A––3 is supplemental data provided for informational purposes. We used the recommended values from Table A––2 of these guidance documents to calculate visibility using the original IMPROVE equation. As discussed elsewhere in this response to comments, we find that our CALPUFF visibility modeling was necessary to assess the anticipated visibility improvements from the use of dry and wet scrubbers at the achievable emission rates that were determined during our analysis of the available control technology. We performed our CALPUFF visibility modeling following EPA/FLM guidance and practices. As detailed in the following response to comment, we used the revised IMPROVE equation to estimate visibility impacts. The revised IMPROVE equation utilizes a separate set of relative humidity adjustment factors available from the Federal Land Managers’’ Air Quality Related Values Work Group (FLAG) Phase I Report.12 We also evaluated modeling results using the original IMPROVE equation to quantify the sensitivity 11 ““Guidance for Tracking Progress Under the Regional Haze Rule,”” EPA––454/B––03––004, September 2003. 12 ““Federal Land Managers’’ Air Quality Related Values Work Group (FLAG) Phase I Report——Revised (2010) Natural Resource Report NPS/ NRPC/NRR——2010/232,”” National Park Service, U.S. Department of the Interior, available at http://www.nature.nps.go V/air/Pubs/pdf/flag/ FLAG_2010.pdf. App. 120 of our results to the choice in visibility impairment algorithm. In applying the original IMPROVE equation for this sensitivity analysis, we utilized the recommended relative humidity factors provided in the guidance. Comment: AEP/PSO stated that ODEQ used the most up-to-date version of the visibility model available and utilized the original IMPROVE equation that was approved for use at the time the SIP was prepared. The commenter stated that when we performed our modeling we used the revised IMPROVE equation. The commenter states that the use of this different equation is the largest variable causing the ODEQ modeling results to be different from our modeling results. The commenter concludes that because ODEQ used the most up-to-date version of the equation at the time the SIP was prepared, the subsequent release of new methods should not be the basis for overriding the results provided in the SIP. Response: The original IMPROVE equation and the revised IMPROVE equation refer to two different versions of algorithms used to estimate visibility impairment from pollutant concentrations. The revised equation is a more recently available, refined version of the original equation and is now considered by EPA and FLM representatives to be the better approach to estimating visibility impairment. Compared to the original IMPROVE equation, this revised IMPROVE equation has less bias, accounts for more pollutants, incorporates more recent data, and is based on App. 121 considerations of relevance for the calculations needed for assessing progress under the RHR.13 As discussed elsewhere in this response to comments, it was necessary for us to perform CALPUFF visibility modeling to assess the anticipated visibility improvements from the use of dry and wet scrubbers at the achievable SO2 emission rates of 0.06 and 0.04 lb/MMBtu, respectively for Step 5 of the BART analysis. As part of our BART analysis, we performed CALPUFF modeling to assess the impacts of the SO2 BART proposed controls on the sources at issue on visibility impairment. Because the revised IMPROVE equation is the preferred method for analyses being conducted at this time,14 we estimated 13 Revised IMPROVE algorithm for Estimating Light Extinction from Particle Speciation Data, IMPROVE, January 2006 (http://vista.cira. colostate.edu/improve/Publications/GrayLit/ gray_literature.htm); Hand, J.L., Douglas, S.G., 2006, Review of the IMPROVE Equation for Estimating Ambient Light Extinction Coefficients——Final Report (http://vista.cira.colostate.edu/improve/ Publications/GrayLit/016_IMPROVEEeqReview/IMPROVEeq Review.htm). 14 U.S. EPA. Additional Regional Haze Questions. U.S. Environmental Protections Agency. August 3, 2006, available at http://www.wrapair.org/forums/iwg/documents/Q_and_A_for _Regional_Haze_8––03––06.pdf#search=%22%22 New%20IMPROVE %20equation%22%22; WRAP presentation, ““Update on IMPROVE Light Extinction Equation and Natural Conditions Estimates”” Tom Moore, May 23, 2006; U.S. Forest Service, National Park Service, and U.S. Fish and Wildlife Service. 2010. Federal land managers’’ air quality related values work group (FLAG): phase I report——revised (2010). Natural Resource Report NPS/NRPC/NRR——2010/232. National Park Service, Denver, Colorado. App. 122 the CALPUFF visibility impacts using this peer reviewed algorithm. We also evaluated modeling results using the original IMPROVE equation to quantify the sensitivity of our results to the choice in visibility impairment algorithm. Visibility benefits estimated using the original IMPROVE equation were larger than those estimated with the revised IMPROVE equation at all four Class I areas included in the modeling. We note that, using either equation, visibility benefits were projected for the installation of scrubbers and support the conclusion that dry scrubbers are the appropriate BART control for each facility. Comment: AEP/PSO states that we incorrectly compared baseline visibility impairment with visibility improvement for controlled cases. The commenter states that both the Oklahoma SIP and the proposed FIP compared an inherently higher 24-hour average for the baseline with an inherently lower 30-day average for the controlled case. The commenter states that the same averaging period should be used so decisions are not biased toward greater SO2 emission reductions. The commenter also states that our analysis is consistent with many other BART analyses and determinations prepared by EPA, states and industry, but inconsistent with the proposed BART determination for the Four Corners Power Plant in New Mexico and BART guidance from the State of Colorado. Response: The approach that we have taken for estimating the visibility impacts of wet and dry scrubbing is appropriate based on the approach set out in the BART Guidelines. The BART guidelines state that in estimating visibility impacts: App. 123 Use the 24-hour average actual emission rate from the highest emitting day of the meteorological period modeled (for the precontrol scenario). Calculate the model results for each receptor as the change in deciviews compared against natural visibility conditions. Post-control emission rates are calculated as a percentage of pre-control emission rates. For example, if the 24-hr pre-control emission rate is 100 lb/hr of SO2, then the post control rate is 5 lb/hr if the control efficiency being evaluated is 95 percent. The BART guidelines also state: The emissions estimates used in the models are intended to reflect steady-state operating conditions during periods of high capacity utilization. We do not generally recommend that emissions reflecting periods of start-up, shutdown, and malfunction be used, as such emission rates could produce higher than normal effects than would be typical of most facilities. The BART guidelines provide a consistent approach to assess the visibility improvement due to the installation of controls allowing comparison between BART assessments. Setting the baseline using the highest emitting day during the period being assessed provides a consistent approach for sources to assess their baseline impacts and gives an assessment of the maximum impact the source will have on visibility. ODEQ, EPA and AEP agreed on how to model the baseline emissions, including the baseline emission rates, in a previous modeling protocol and subsequent modeling reports. ODEQ’’s RH SIP, and EPA’’s proposed App. 124 FIP incorporated this same baseline emission rate approach that is consistent with previous agreements and analyses that AEP had conducted. In modeling the post-control emission rates, we considered the reasonably anticipated control efficiency of the available control technology taking into account that the BART modeling should reflect steady-state operating conditions and should not generally reflect periods of start-up, shutdown and malfunction. As discussed previously in our TSD and elsewhere in this notice and the Supplemental RTC, control efficiencies reasonably achievable by dry scrubbing and wet scrubbing were determined to be 95% and 98% respectively. We also note that OG&E directed its vendors to provide bids on a dry SO2 scrubber system that was designed to remove 95% of the SO2. The two AEP sources were modeled with baseline SO2 emission rates of 5230.8 and 5034.6 lb/hr for Units #3 and #4 respectively. These rates for the two AEP sources were modeled using the firing rate of each unit with baseline SO2 emission rates of 0.9 lb/MMBtu which, as discussed above, are the same rates, previously provided by AEP and utilized by ODEQ in the Oklahoma RH SIP for the baseline emission rates. Applying the expected 95% reduction in emission rates for a dry scrubber, in accordance with the example given in the BART guidelines, would result in an emission rate of 0.045 lb/MMBtu. This value is lower than our proposed BART SO2 emission limit of 0.06 lb/MMBtu. The 0.06 lb/MMBtu emission limit we chose was based on a thorough review of achievable emission rates of current Dry Flue Gas Desulfurization (DFGD) scrubbers and the example method for the BART guidelines that yields 0.045 lb/MMBtu is not App. 125 appropriate in this case for estimating future emission rate for modeling. We chose to model the future SO2 emission rate of 0.06 lb/MMBtu rather than 0.045 lb/MMBtu because this is consistent with our proposed BART emission limit and is a reasonable estimate of future emissions in order to estimate the future visibility improvement from baseline levels. Our approach of modeling the proposed emission limit is consistent with the approach taken by ODEQ in their SIP and in our action on the BART FIP for the State of New Mexico and is not as conservative as using the emission rate based on percentage reduction as outlined in the BART guideline. As discussed elsewhere, the BART determination is based on consideration of five factors, including the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. The visibility modeling is intended to give a reasonable best estimate of the visibility impacts from an evaluation of emission reductions. The visibility analysis is only one of the factors in a BART determination. In this final action, we are setting a SO2 limit of 0.06 lb/MMBtu to be calculated on a 30-day rolling average Boiler Operating Day. We modeled the 0.06 lb/MMBtu in our proposal, which equates to a 93 percent reduction in emissions, because we have determined this emission rate to be achievable. This percentage reduction is less than would be expected from the installation of a DFGD that has been optimally designed (refer to Figure 7 and 8 of the Supplemental RTC and the associated responses to comments). App. 126 We recognize that sources complying with a 30 day average may at times operate above the 30 day average emission limit but they will have to balance those times by operating below the limit at other times. This variability is difficult to assess, though a prudent source will strive to remain below the 30-day emission limit as much as possible. In some instances, it may be appropriate to model a slightly higher emission rate when limiting the emissions using a 30-day average to account for potential variability, when the amount of variability is well understood. In this case, we believe using the 30 day average emission limit is a reasonable approach to project future emissions that would reasonably be anticipated in accordance with BART guidelines because we have no reason to think the variability in the future case will be large enough to impact our evaluation of the five factors. We did not believe it was appropriate to assess variability based on past history of emissions at the facilities because there is inherently more variability in historic data when facilities are not specifically controlling to achieve low SO2 emissions and the facility emissions instead can vary due to the range of types of coal purchased. As the limits are reduced to a level in the range that was proposed in our action, the amount of variability that would exist is expected to decrease, as the source must demonstrate compliance on a 30-day BOD compliance level with a much tighter limit than it had previously. We have seen this in evaluation of some sources in comparing their precontrol emission variability with their post-control emission variability. App. 127 As discussed in a later response to comment, we note the TS Power Plant near Dunphy, Nevada, which has a similar permitted SO2 emission limit to our BART FIP, maintained a 30-day BOD emission rate below 0.06 lb/MMBtu for an approximately 20-month period of time in 2010––2011. This plant burns a similar Powder River Basin (PRB) coal as the six AEP/PSO and OG&E units. In addition, the Wygen II facility, located outside Gillette, Wyoming, and the Weston 4 facility, near Wausua, Wisconsin, also burn coal similar to the OG&E and AEP/PSO’’s units and have been able to maintain 30-day BOD SO2 emission rates below 0.06 lb/MMBtu for significant periods of time during the years of 2009––2011. CEM data for the TS Plant (Figure 7 of the Supplemental RTC) shows limited variability in 24-hr emissions. We note that this data includes periods of start-up, shutdown, and malfunction that would normally be considered when evaluating the emission rate to be modeled to represent steady-state operating conditions for BART modeling. In evaluation of other facilities we did find where they had operated for months at a significantly lower emission rate than 0.06 lb/MMBtu, with limited variability under steady-state conditions. The commenter pointed to other actions and guidance concerning emission rate estimates and indicated that we were not consistent with those approaches. The commenter pointed to the EPA Region 9 proposal for the Four Corners power plant, which used the percent reduction approach and the 24-hour maximum actual baseline emission rate to estimate a future controlled emission rate. We note that we evaluated this technique (see discussion earlier in this response) that is outlined in the BART guideline as one App. 128 acceptable technique and it resulted in a value (0.045 lb/MMBtu) that was not reasonable compared to the 30-day emission limit (0.06 lb/MMBtu) that we proposed and determined to be technically feasible. The commenter also pointed to guidance that Colorado has developed for their BART sources that indicates a maximum 24-hour future controlled emission rate should be used in conjunction with using the maximum actual 24-hour baseline emission rate. The BART guidelines state: Make the net determination. visibility improvement Assess the visibility improvement based on the modeled change in visibility impacts for the pre-control and post-control emission scenarios. You have flexibility to assess visibility improvements due to BART controls by one or more methods. You may consider the frequency, magnitude, and duration components of impairment. The BART guidelines allow for some flexibility in how to assess visibility improvements due to BART controls. As we discuss elsewhere in this response, we consider issues related to frequency, magnitude and duration of emission levels that may occur in comparison to our proposed 0.06 lb/MMBtu 30-day limit and the potential for impacting the visibility projections. We concluded that the amount of times the variability of emissions would exceed 0.06 lb/MMBtu on a maximum daily process would not be expected to be of sufficient magnitude to have a large impact on our visibility improvement estimates. We agree that the App. 129 BART guidelines allow for some flexibility in how visibility improvement determinations are conducted. We considered processes similar to Colorado’’s approach, including the methodology given as an example in the BART guidelines, but determined we did not have sufficient information to accurately estimate the future maximum 24-hour emission rate and furthermore concluded that existing modeling indicated that small changes would not significantly impact our visibility improvement estimates. Overall, the BART guidelines give some flexibility to how the visibility improvements can be calculated and the approach that we have used is reasonable based on the information available and is not inconsistent with the BART guidelines. We conducted modeling for future emission rates of 0.04 and 0.06 lb/MMBtu of SO2 in our proposal. We note that at these low SO2 emission rates, the most impacted days were more nitrate driven days because the SO2 rates were low. Therefore, a slight increase in emission rates on the order of 10% or so for a maximum 24-hour emission rate would not be expected to result in much change in visibility estimates. We do note that other modeling conducted by the source’’s consultants and the state indicates that a significant increase in the controlled SO2 emission rate would decrease the visibility impairment improvements from installation of controls and result in much lower relative visibility improvement. As further discussed elsewhere in this response we find our future emission rate to be a reasonable assessment of the visibility improvement due to the setting of a 0.06 lb/MMBtu on a 30-day BOD limit. App. 130 In summary, we find our approach to modeling the baseline and control case emissions was a reasonable estimate of reduction in impairment and not inconsistent with the BART guideline. We recognize that it is possible that the facility will operate at slightly higher emission rates at times, but it is also true that to remain in compliance over a 30-day rolling average, it will also have to operate at lower emission rates than 0.06 lbs/MMBtu. Furthermore, we have shown that other facilities have demonstrated that it is feasible to operate below 0.06 lbs/MMBtu for extended periods of time. Finally, we have noted that even if emissions are slightly higher than 0.06 lbs/MMBtu, at times, it would not be expected to increase the visibility impairment significantly because at these low concentrations, visibility impairment due to AEP/PSO sources is primarily due to nitrates. We find the approach for estimating improvements in visibility due to our proposed emission level that we have used is appropriate based on the information available and is not inconsistent with the BART guidelines. For these reasons, we believe the proposal was based on a reasonable assessment of visibility improvements for consideration as one of the five factors of the BART decision. Comment: A commenter submitted a review of our modeling results for controlling SO2 emissions, noting a 2.89 deciview improvement in visibility at the Wichita Mountains and a cumulative improvement in visibility total of 8.20 deciviews. The commenter believes our CALPUFF modeling is appropriate and concurs with our emission calculations and speciation. They do, however, note several ““possibly incorrect input values”” regarding base elevations of several units and App. 131 the stack gas exit velocity of one unit. The commenter expressed the view that corrected values would not substantially change results and conclusions. The commenter also contends that EPA’’s proposed SO2 BART may benefit Oklahoma and the facilities, because the commenter believes that based on results of their dispersion modeling, the units are currently contributing to violations of the one-hour SO2 NAAQS. Response: We agree with the commenter that our modeling calculations and speciations are appropriate. We further agree with the commenter’’s noted visibility improvement resulting from the SO2 controls that we are requiring in the FIP. It is true that states will be required to submit plans demonstrating attainment or maintenance of the new one-hour SO2 NAAQS. However, this is not a consideration for our action, which is directed solely to ensuring the state has met the BART requirements of the RHR and the requirements of CAA section 110(a)(2)(D)(i)(II). With respect to the noted ““possibly incorrect input values,”” we agree that correcting these values would not substantially change our results and conclusions. E. Summary of Responses to Comments on the SO2 BART Cost Calculation We received many comments on issues concerning our cost calculations for our proposed SO2 BART determinations on the six OG&E and AEP/PSO units. The full text received from these commenters is included in the docket associated with this action. Additionally, our summary and response for these comments is provided in the ““Response to Technical Comments for Sections E through H of the Federal Register Notice for the Oklahoma Regional Haze and App. 132 Visibility Transport FIP,”” (or Supplemental RTC), and it is available in the docket. Although we summarize them here, please see the Supplemental RTC for a full accounting of the issues and how they influenced our final decision. We deviate in sections E., F., G., and H., from the comment-response format of the rest of the notice, as many of the comments summarized herein were drawn from multiple, lengthy, and highly technical comments. The significant aspects of our approach to cost estimations in consideration of all comments are summarized in this section. Overall, our final rulemaking retains the basis for the cost effectiveness evaluation and cost estimates we employed in our proposal. However, as discussed in more detail below, we are changing several factors in the cost calculations for the four OG&E units as a result of the comments we received. We are making no changes to the cost calculations for the two AEP/PSO units. 1. Control Cost Manual Methodology The Control Cost Manual must be followed to the extent possible when calculating the cost of BART controls.15 This is necessary to ensure that a consistent 15 Very limited situations exist under which an analyst can depart from the Control Cost Manual methodology under the RH rule. ““The basis for equipment cost estimates also should be documented, either with data supplied by an equipment vendor (i.e., budget estimates or bids) or by a referenced source (such as the OAQPS Control Cost Manual, Fifth Edition, February 1996, EPA 453/B––96––001). In order to maintain and improve consistency, cost estimates should be based on the OAQPS Control Cost Manual, where possible. The Control Cost Manual addresses App. 133 methodology is used when comparing cost effectiveness determinations. The Control Cost Manual allows sitespecific conditions to be incorporated in certain circumstances. Site-specific conditions can include vendor quotes, space constraints, a design feature that could complicate installing a control, or unusual circumstances that introduce a cost not contemplated by the Control Cost Manual. OG&E incorporated many of these into its cost evaluation. However, the RHR specifically requires that the analyst document any such site-specific conditions.16 Thus, the RHR places the burden on the analyst to make this demonstration, and on EPA to approve it, disapprove it, or document it when promulgating a FIP. Nevertheless, with the exceptions noted herein and in our Supplemental RTC, we approved many of those site-specific cost modifications. The Control Cost Manual uses the overnight method of cost estimation, widely used in the utility industry. 1 7 The U.S. Energy Information Administration (EIA) defines ““overnight cost”” as ““an estimate of the cost at which a plant could be most control technologies in sufficient detail for a BART analysis.”” 70 FR 39104, at 39166. 16 A cost determination can deviate from the Control Cost Manual methodology if you ““include documentation for any additional information you used for the cost calculations, including any information supplied by vendors that affects your assumptions regarding purchased equipment costs, equipment life, replacement of major components, and any other element of the calculation that differs from the Control Cost Manual.”” Id. 17 See Control Cost Manual, Section 2.3 to 2.4. App. 134 constructed assuming that the entire process from planning through completion could be accomplished in a single day. This concept is useful to avoid any impact of financing issues and assumptions on estimated costs.””18 EIA presents all of its projected plant costs in terms of overnight costs. The overnight cost is the present value cost that would have to be paid as a lump sum up front to completely pay for a construction project.19 The overnight method is appropriate for BART determinations because it allows different pollution control equipment to be compared in a meaningful manner. Because ““different controls have different expected useful lives and will result in different cash flows, the first step in comparing alternatives is to normalize their returns using the principle of the time value of money * * * . The process through which future cash flows are translated into current dollars is called present value analysis. When the cash flows involve income and expenses, it is also commonly referred to as net present value analysis. In either case, the calculation is the same: Adjust the value of future money to values based on the same point in time (generally year zero of the project), employing an appropriate interest (discount) rate and then add them together.””20 This is the overnight method, in which costs are calculated based on current 18 EIA, ““Updated Capital Cost Estimates for Electricity Generation Plants,”” November 2010, footnote. 2, available at: http://www.eia. gov/oiaf/beck_plantcosts/?src=email. 19 Steven Stoft, Power Economics: Designing Markets for Electricity, 2002. 20 Id., page 2––18. App. 135 dollars. Therefore, consistent with our proposal, we find that the overnight method is appropriate for calculating costs for all six units. OG&E and others incorrectly assume that BART cost effectiveness should be based on the ““all-in”” cost method, which includes all of the costs of a financial transaction, including interest, commissions, and any other fees from a financial transaction up to the date that the project goes into operation, as of the assumed commercial operating dates of the scrubbers, 2014 and 2015. This is an entirely different method than that prescribed in the Control Cost Manual. OG&E and others conclude that dry scrubbers are not cost effective for the six units, based on all-in costs reported in 2014 to 2015 dollars, compared to costs estimated at other similar facilities based on overnight costs and 2009 and earlier dollars. This comparison is an invalid because OG&E’’s 2014 and 2015 all-in costs are much higher than the corresponding overnight costs, as prescribed by the Control Cost Manual. This makes the estimated cost of scrubbers at the six units appear to be higher than scrubbers required at other similar facilities costed using the overnight method. Many of the corrections we make to ODEQ’’s cost estimates for the six OG&E and AEP/ PSO units are due to the fact that ODEQ did not follow this provision of the Control Cost Manual in its SIP submittal. Please refer to our Supplemental RTC in the docket for more information about how the overnight costing methodology is employed by the Control Cost Manual. 2. Revised Cost Calculations for the OG&E Units OG&E’’s cost estimates deviate from the Control Cost Manual, which is based on the overnight cost App. 136 approach. In its cost estimates, OG&E has improperly included allowances for excessive contingencies allowances for funds during construction (AFUDC), double counted certain expenses, and improperly relied on the Electric Power Research Institute (EPRI) cost model, CUECost. These deviations from the Control Cost Manual, occurring because of the reliance upon the all-in cost methodology, artificially increase the cost of scrubbing at Sooner and Muskogee, compared to the cost at other similar facilities using the overnight cost methodology. OG&E’’s cost estimates relied on vendor quotes and site specific estimates for certain additional costs. We support the use of vendor quotes and site specific estimates but only as used within the parameters of the overnight cost methodology. The Guidelines, cited in this comment, are clear that ““[y]ou should include documentation for any additional information you used for the cost calculations, including any information supplied by vendors that affects your assumptions regarding purchased equipment costs, equipment life, replacement of major components, and any other element of the calculation that differs from the Control Cost Manual.””21 However, much of the documentation OG&E and others cite to support deviations from the Control Cost Manual was not provided to us. Thus, we were unable to analyze their contents and determine whether these deviations were appropriate. Also, although OG&E provided two spreadsheets that listed its cost line items, these spreadsheets, each over 600 lines in length, were stripped of all formulas for cell 21 70 FR 39104, at 39166, footnote 15. App. 137 calculations, preventing any meaningful review, despite our request for that material. Capital Recovery Factor We are changing one input to the cost calculations for the four OG&E units based on a comment we received from OG&E concerning the Capital Recovery Factor (CRF). OG&E states that, while the Control Cost Manual includes a default rate of 7% for the social discount interest rate, we should use a site-specific social discount interest rate for the four OG&E units. This rate includes several site-specific variables, including income tax. The commenter states that the CRF includes not only recovery of principal but also a return on the principal, with the rate of return equal to the discount rate. OG&E states that for an investor owned utility, such as itself, which is financed by a mix of debt and equity, the discount rate is equal to the weighted average of the equity return and debt return. We agree that a site-specific social discount interest rate is appropriate based on the documentation provided by the commenter. However, we disagree that such a rate can include income tax. The Control Cost Manual states ““this Manual methodology does not consider income taxes.”” Control Cost Manual, page 2––9. The site-specific social discount interest rate, excluding income tax, is 6.01%, which is less than the default rate of 7%. Thus, we have revised our cost effectiveness analysis in Exhibits 1 and 2 for Options 1 and 2, to use the levelized interest rate of 6.01%, as reported by OG&E, adjusted to remove income taxes. This rate is consistent with OG&E’’s real average cost of capital and falls within the range of 3% to 7% recommended by OMB for regulatory cost analyses. This correction App. 138 moderately improved the cost effectiveness, thus lowering the calculation of $/ton SO2 removed. For detailed information on our calculation, please see the Supplemental RTC. Construction Management In our proposal, we revised the cost estimate to remove what we took to be double counting of the Balance of Plant (BOP) construction management costs. OG&E explained in a comment that crew wage rates do not include contractor general and administrative (G&A) costs and that construction management is the cost of third-party construction management, different from the BOP profits contractor and different from the owner. Based on this explanation, we have restored the construction management costs in our revised Options 1 and 2 cost estimates in Exhibits 1 and 2. This correction slightly diminished the cost effectiveness, thus raising the calculation of $/ton SO2 removed. Scrubber Design and Emission Baseline Mismatch We retain both our Option 1 and Option 2 cost effectiveness approaches to the mismatch between the design of OG&E’’s SO2 scrubbers and the coal they currently burn. OG&E specified to its vendors that they provide cost estimates for SO2 scrubber systems designed to treat the exhaust gases from a coal that contains much higher amounts of sulfur than coals that were typically burned in the baseline period (2004––2006). However, in calculating the cost effectiveness, OG&E used its historical baseline emissions, which resulted from the burning of those lower sulfur coals. Thus, OG&E costed scrubbers that App. 139 were overdesigned based on the coal that was, and is, typically burned. This resulted in two errors that both combined to make the control technology appear less cost effective. First, the BART Guidelines require that we calculate cost effectiveness on the basis of annualized cost divided by tons of pollutant removed from the emissions baseline ($/ton). Therefore, use of a baseline that is lower than would result from burning the higher sulfur coal the scrubber was designed to treat, lowers the denominator in the $/ton equation, and skews the cost effectiveness calculation to appear less cost effective. We account for this mismatch in Option 1 by raising the baseline to match the higher sulfur coal the scrubber system was designed to treat. Second, although we have adjusted our calculation in response to OG&E’’s comments, we conclude that the over designed scrubber system was more expensive than necessary to treat the coal OG&E historically burned and continues to burn. We account for this mismatch in Option 2 by slightly decreasing the capital costs to reflect a scrubber designed to treat the exhaust gases from the coal OG&E has historically burned, while retaining the historical emission baseline. We find that, whether OG&E chooses to burn its current coal, or burn a coal that its scrubber system was designed to treat, the resulting cost effectiveness lies in the range defined by Options 1 and 2 (below). We find that both options are cost effective in light of the five-step BART analysis. App. 140 Cost Adjustment of Scrubber in Option 2 As we describe above, in calculating cost effectiveness under Option 2 in our proposal, we also analyzed the cost of a dry scrubber for the OG&E units, assuming the scrubber would be re-sized to scrub the coal being currently burned. We did this using a cost scaling equation based on the differences between the sulfur content of the coal OG&E typically burns versus the coal their scrubber system was designed to treat. OG&E responded in a comment to us that the exhaust gas flow rate, rather than the sulfur content, is the primary variable that affects scrubber sizing. Thus, the use of a higher sulfur coal would not significantly affect the size, and hence the cost of a scrubber. Based on the information OG&E supplied, we re-adjusted the cost of Option 2 based on certain design algorithms in the dry scrubber absorber (SDA) cost model developed by OG&E’’s contractor, Sargent & Lundy for EPA.22 The results of this analysis indicate that the use of the lower sulfur coal alone would reduce the capital cost of the scrubber by about $7 million or 3%. Other Issues Concerning Site-Specific Costs In addition to those comments that resulted in a modification to our cost basis, two others merit particular emphasis. These comments led us to investigate two other line item costs to determine whether we underestimated the costs of the scrubbers for the four OG&E units by not using site-specific 22 Sargent & Lundy, IPM Model——Revisions to Cost and Performance for APC Technologies, SDA FGD Cost Development Methodology, Final, August 2010, Table 1. App. 141 values. We determined that, even if we made changes to the cost calculations to account for these site-specific cost line items, the cost of controls would be even more cost-effective than our proposed range. These line items costs are: (1) Auxiliary power; and (2) capacity factor for Option 2. These issues were uncovered during the course of preparing our response to comments, but did not directly follow from information provided by the comments. Thus, we did not further modify our cost basis, but discuss these issues as they serve to further illustrate why we believe our cost basis likely overestimates the costs of control and that our conclusions that dry scrubbers for the six OG&E and AEP/PSO units are cost effective and are reasonable. a. Auxiliary Power We received a comment that EPA incorrectly lowered OG&E’’s auxiliary power costs for the DFGD/FF control systems on the premise that the unit cost of electricity used in the cost estimate was higher than the cost to OG&E to produce electricity. Auxiliary power is the sum of the demand by the scrubber, baghouse, and booster fans (the latter required to overcome the increase in backpressure from adding these controls) and is accounted for in a BART cost effectiveness analysis. OG&E used average year-round market retail rates of $85.93/MWh (2015 dollars) for Sooner and $83.83/MWh (2014 dollars) for Muskogee as the best long-run measure of auxiliary power costs. The cost of auxiliary power affects the cost effectiveness calculation in both Option 1 and Option 2. We have concluded that our proposed cost of $50/MWh is an appropriate estimate of the cost of auxiliary power for the four OG&E units. We arrived at App. 142 this number because OG&E’’s summary of auxiliary power costs indicates the range used for other similar facilities is $30/MWh to $50/MWh.23 We took the most conservative view based on this report and adopted the highest value in this range. However, even if we were to take OG&E’’s view that a site-specific auxiliary power cost is more appropriate, we disagree that we could use the market-value of power for purposes of the BART determination because the utility would not pay market price. We estimate that the actual site-specific cost of auxiliary power for the four OG&E units is no more than $36/MWh. However, because we arrived at this figure due to independent research that we do not view as being a logical outgrowth of the comment we received, we have not revised our cost effectiveness analysis to use $36/MWh. Instead, we retain the $50/MWh figure we proposed. We view this example as further evidence that OG&E’’s scrubber costs are artificially inflated, and that the cost of controls under both options in our FIP is reasonable. b. Capacity Factor in Option 2 ODEQ calculated future annual emissions assuming a 90% capacity factor. In comparison, during the years that established the emission baseline (2004––2006), the units operated only 78.5% of the time, on average. Thus, ODEQ’’s calculation of emission reductions from scrubbers compares uncontrolled 2004––2006 baseline emissions, when the units operated at 78.5% of 23 December 28, 2009 S&L FollowUp Report, Attach. C, pdf 109 (Gerald Gentleman——$45.65/ MWh;White Bluff——$47/MWh; Boardman/Northeastern/Naughton——$50/MWh; Nebraska City——$30/MWh). App. 143 capacity, to controlled emissions when burning a higher sulfur coal, with the units operating at 90% capacity. This mismatch results in two errors in estimating the cost of Option 2: The future emissions were overestimated, but certain operating costs were underestimated. Correcting these errors in the cost calculations would make Option 2 even more cost effective than our proposed calculations, as the resulting decrease in the operating costs would offset the increase in the capacity factor in the $/ton calculation. However, because we arrived at these errors due to independent research that we do not view as being a logical outgrowth of the comment we received, we have not revised our cost effectiveness analysis in Option 2. We view this example as further evidence that OG&E’’s scrubber costs are artificially inflated, and that the cost of controls under both options in our FIP is reasonable. We made no additional changes to our cost evaluation as a result of the comments we received. As summary of our final $/ton cost effectiveness calculations are provided below: Proposal (Sooner/Muskogee) Final (Sooner/Muskogee) Option 1 $1,291/$1,317 $1,239/$1,276 Option 2 $2,048/$2,366 $2,747/$3,032 App. 144 3. Cost Calculations for the AEP/PSO Units We received a number of comments from AEP/PSO concerning our SO2 BART cost estimate for the two Northeastern units. Some of these comments objected to our incorporation of OG&E’’s site specific information in AEP/PSO’’s scrubber cost estimate. Other comments objected to specific line item costs in our cost estimates for both wet and dry scrubbers. We proposed the cost effectiveness of dry scrubbing to be $1,544/ton, and the cost effectiveness of wet scrubbers to be approximately 9% more. As we note in more detail in our separate Supplemental RTC, the ODEQ SO2 BART evaluation of AEP/PSO Northeastern units 3 and 4 does not provide any support for its assumption that the cost of dry scrubbers is $555/kW to $582/kW, figures we consider to be high in comparison to other BART scrubber determinations. However, the Northeastern units are very similar to the Sooner and Muskogee units, for which vendor quotes were available for dry scrubbers. We used these vendor quotes to support our cost analysis for the Northeastern units. After having reviewed all comments concerning our SO2 BART cost estimates for the AEP/ PSO units, we have determined that no changes were warranted to our proposed cost estimates. Thus, absent any supporting information from AEP/PSO for any of the capital costs it presents, we find our BART SO2 cost evaluation to be well founded, representative of the AEP/PSO units in question, and based on the best information available to us. 4. Conclusion We find that under Option 1, the costs to comply with the FIP will be $1,239/ton for Units 1 and 2 of the App. 145 OG&E Sooner plant and $1,276/ton for Units 4 and 5 of the OG&E Muskogee plant. Under Option 2, the cost to comply with the FIP will be $2,747/ton for Units 1 and 2 of the OG&E Sooner plant and $3,032/ton for Units 4 and 5 of the OG&E Muskogee plant. For Units 3 and 4 of the AEP/PSO Northeastern plant, we find that the costs to comply with the FIP remain at $1,544/ton, as we proposed. We find these ranges to be cost effective for these six units under the five-step analysis for BART under the RHR. As previously stated, our complete, technical responses to comments received on the issue of costs are in the Supplemental RTC in the docket. F. Summary of Responses to Visibility Improvement Analysis Comments We received comments on Step 5 of BART: Degree of improvement in visibility which may reasonably be anticipated to result from the use of scrubber technology. Commenters contested our determination that OG&E and AEP/PSO’’s facilities significantly contribute to visibility impairment. We explain that we find that dry scrubbers are cost effective for the six OG&E and AEP/PSO units, in light of the visibility improvement these controls are predicted to achieve. Commenters also disputed our determination not to use the $/deciview metric in the Step 5 BART analysis when this approach was used by ODEQ. OG&E provided a $/deciview analysis for its units and comparable BART determination performed by us. In our analysis for our BART FIP for OG&E and AEP/PSO, we did not evaluate $/deciview. We explain that the BART Guidelines list the $/deciview metric as an optional cost effectiveness measure that can be App. 146 employed along with the required $/ton metric for use in a BART evaluation. The metric can be useful in comparing control strategies or as additional information in the BART determination process; however, due to the complexity of the technical issues surrounding regional haze, we have never recommended the use of this metric as a cutpoint in making BART determinations. We note that to use the $/deciview metric as the main determining factor would most likely require the development of thresholds of acceptable costs per deciview of improvement for BART determinations for both single and multiple Class I analyses. We have not developed such thresholds for use in BART determination made by us. As OG&E acknowledges, EPA did not use this metric as part of its proposed BART determinations for either the Four Corners Power Plant FIP in AZ, or the San Juan Generating Station FIP in NM. Generally speaking, while the metric can be useful if thoughtfully applied, we view the use of the $/deciview metric as suggesting a level of precision in the calculation of visibility impacts that is not justified in many cases. While we did not use a $/deciview metric, we did, however, consider the visibility benefits and costs of control together, as noted above by weighing the costs in light of the predicted visibility improvement. G. Summary of Responses to Comments Received on the SO2 BART Emission Limit We received comments stating we did not adequately support our SO2 BART emission limit of 0.06 lbs/MMBtu for the six OG&E and AEP/PSO units. In analyzing the control technology, the RHR mandates that we take into account the most stringent emission App. 147 control level that the technology is capable of achieving. 70 FR 39104, at 39166. In accordance with the RHR, when identifying an emissions performance level to evaluate under BART, consideration of recent regulatory decisions and performance data (e.g. manufacturer’’s data, engineering estimates, and the experience of other sources) is required. Id. In determining our SO2 BART emission limit of 0.06 lbs/MMBtu, we drew on a number of sources of information. These include industry reports, vendor quotes, the engineering analysis contained in the TSD, and the historical emissions data for other similar coal fired power plants. As we state in the TSD and affirm, a dry scrubber at Sooner or Muskogee, designed as costed, could meet an SO2 emission limit of 0.06 lb/MMBtu based on 30-day BOD average, when burning coal containing 0.51 to 1.18 lb/MMBtu SO2. We conclude the same is true for the AEP/PSO Northeastern units because they have historically burned coal with a sulfur content within this range.24 Among other objections, OG&E states we cannot rely on the SO2 emission performance of new facilities as an indicator of the performance potential of retrofit scrubbers. OG&E presents data on what it states are the best performing scrubber installations in the United States, and contends that the lowest emission rate achieved by a retrofit on an annual basis is 0.088 lbs/MMBtu. We explain that a scrubber, regardless of type, is not influenced by whether the flue gas comes from a new boiler or an old boiler located in an existing plant. The scrubber merely reacts to 24 TSD, Appendix C, page 43. App. 148 physical and chemical characteristics of the gas stream. Therefore, although we use other sources of information to justify our SO2 BART emission limit, we find that considering emission data from new scrubber installations to support our decision is appropriate. In so doing, we analyzed the historical emissions data of several units that we discuss above in response to another comment, which OG&E included in its comment. We reviewed the performance of three units that are of similar size and burn similar coal. One unit, TS Power Plant, has an emission limit that requires emissions to be significantly controlled and has been able to maintain its emissions below 0.06 lbs/MMBtu on a 30 day BOD basis continuously. We also reviewed the performance of two other units that demonstrate the ability to maintain emissions below the 0.06 lbs/MMBtu limit for long periods of time. We note that these units do not have as constraining emission limits so they do not have to control their emissions as closely. This and other sources of information we outline above and in our Supplemental RTC cause us to conclude our proposed SO2 BART emission limit of 0.06 lbs/MMBtu, calculated on the basis of a 30 day BOD, for the six OG&E and AEP/PSO units is technically feasible and therefore the correct SO2 limit for BART. OG&E also states that we should include in our proposed SO2 BART emission limit a compliance margin. OG&E suggests that a SO2 emission of 0.10 is required to provide a ““reasonable margin for operating fluctuations and compliance.”” We reply that we are modifying the compliance averaging period from a 30 calendar period to a 30 day Boiler Operating Day (BOD) period. As the BART Guidelines direct, ““[y]ou App. 149 should consider a boiler operating day to be any 24hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time at the steam generating unit.””25 To calculate a 30 day rolling average based on boiler operating day, the average of the last 30 ““boiler operating days”” is used. In other words, days are skipped when the unit is down, as for maintenance. This, in effect, provides a margin by eliminating spikes that occur at the beginning and end of outages, and is consistent with the BART Guidelines. In our separate Supplemental RTC, we also discuss several other objections OG&E raises in its comments. These include objections to our reliance on a National Lime Association scrubber performance chart, OG&E’’s contention that our proposed SO2 BART emission is more representative of a LAER limit, and the technical capability of dry scrubbing. After addressing these issues, we find that our proposed SO2 BART emission for the six OG&E and AEP/ PSO units remains at rate of 0.06 lbs/MMBtu. H. Summary of Responses to Comments Received on the SO2 BART Compliance Timeframe We proposed that compliance with our SO2 BART emission limits be within three years of the effective date of our final rule. We solicited comments on alternative timeframes, from as few as two (2) years to up to five (5) years from the effective date of our final rule. We received comments that retrofitting of scrubbers is now routine in the United States and that 25 70 FR 39104, at 39172. App. 150 approximately 290 coal-fired units totaling about 116,000 MW nationwide have been retrofit with scrubbers since 1990. The commenter cites to many examples of SO2 scrubbers being installed at coal-fired power plants within a three year timeframe. OG&E and others state that our proposed three year schedule focuses on actual construction timelines, but fails to acknowledge or allow sufficient time for the engineering, design, and permit processes that must be completed prior to the commencement of construction. They state a compliance schedule of from 52––54 months would be required. Although we do not specify what technology the six OG&E and AEP/PSO units must use to satisfy the SO2 BART emission limit, we expect that either dry or wet SO2 scrubbers will be used, or that the SO2 limit will be met by switching one or more of the units to natural gas. We agree that SO2 scrubbers have been installed at other facilities with construction timeframes of three years or less. However, we also agree with OG&E and AEP/PSO that there may be issues such as PSD permitting, and the construction/expansion of a landfill that may not be reflected in the example compliance times reported by the commenter. Therefore, we find that compliance with the emission limits be within five years of the effective date of our final rule. I. Comments Supporting Conversion to Natural Gas and/or Renewable Energy Sources Comment: Several parties submitted comments noting that switching to natural gas-fired electricity is feasible and demonstrated in practice. One of the commenters points out that, of the three subject sites, two have existing major natural gas supplies (OG&E App. 151 Muskogee and AEP/PSO Northeastern) and that fuel switching will require construction of new or expanded natural gas supply and electric interconnection facilities. The commenter states that expanding along existing gas supply lines would cost less and take less time than constructing a new line. The commenters have stressed that natural gas produces comparatively low emissions of many pollutants, including hazecausing pollutants, air toxics, and greenhouse gases. Commenters also noted use of natural gas as a fuel source would eliminate the need to manage coal combustion waste and scrubber waste. Several commenters who support the switch from coal combustion to natural gas combustion cited the availability and abundance of natural gas as a natural resource, particularly in Oklahoma. Response: We agree that switching of existing coalfired power generating units to natural gas, either through conversion of existing boilers or installation of new power generating units, is technically feasible and demonstrated in practice. As stated in our proposal, the owners of the units subject to the FIP may elect to reconfigure the units to burn natural gas as means of satisfying their BART obligations under section 51.308(e). Switching to natural gas would be an acceptable method of complying with the limits proposed in the FIP, because natural gas combustion inherently results in much lower SO2 emissions. We agree that natural gas may result in lower emissions of other pollutants and offer other environmental advantages. The owners of each subject unit may take these advantages, as well as the availability and pricing information, into consideration as they evaluate App. 152 this option for complying with SO2 BART emission limits. Comment: Eight commenters responded to our request for comments on the compliance deadline for the six BART-subject units and whether it would be appropriate to extend that deadline for those utilities that elected to switch from coal to natural gas in order to comply with the BART emission limits. Several of these commenters note that switching to natural gas can be accomplished in less than three years if utilities enter into long-term power purchase agreements with existing natural gas-fired power generators but utilities that choose to construct new gas-fired units or convert existing units will likely require more time. They indicate that the requirements to engage in competitive bidding, complete engineering designs, prepare budgets, obtain necessary permits, and equipment installation will likely require up to five years to complete. One of these commenters points out that OG&E has already studied fuel-switching at the system and plant levels and that the typical lead time of construction of new natural gas-fired combined cycle combustion turbines is four years. Numerous commenters express their support for extending the compliance deadline to five years for units that will be converted to, or replaced with, natural gas-fired power generating units. These commenters cite the broad collateral benefits and overall superiority of switching to a cleaner fuel source over installing additional controls on the existing units and continuing to burn coal. Multiple other commenters, however, expressed the opinion that the utilities have had ample time already App. 153 to transition away from coal to cleaner or renewable power generation and that the affected utilities should phase out the BART-subject coal-fired units as quickly as possible. These commenters feel that the proposed compliance deadline of three years is adequate. ODEQ submitted comments supporting a fourteen and one-half month extension (to four years and two and one-half months total) on the installation of scrubbers and a seven and one-half year extension (to ten and one-half years total) for switching to natural gas. Response: We thank the commenters for their responses to our request for comments on the proposed compliance deadline. As we have discussed elsewhere in our response to comments we find that a compliance deadline of five years is appropriate for the six OG&E and AEP/PSO units to comply with our FIP SO2 emission limit. After reviewing the information provided by the commenters, we find that the same compliance deadline of five years is appropriate for any of the six OG&E and AEP/PSO units that elect to comply with the FIP SO2 emission limit by converting an existing unit to natural gas or replacing it with a new, natural gas-fired unit. Comment: Several commenters provided information concerning underutilized electrical generation capacity through natural gas combustion in Oklahoma. One commenter further suggested that fuel switching could be achieved by imposition of annual emissions caps on the BART-subject, coal-fired units. According to the commenter, such a scheme would provide the affected utilities with the flexibility to shift power generation to existing gas-fired generating units App. 154 or purchase power from merchant generators. The commenter states that there is an exception provision in the RH regulations at 40 CFR 51.308(e)(2) that allows for imposition of operating limits on BARTeligible units in lieu of conventional BART reductions if the regulating authority implements an emission trading program. Another commenter noted that switching to natural gas-fired generation, either through conversion of existing units or replacement with new units, would result in power plants better suited to integrate with variable wind power generation. Response: Section 51.308(e)(2) allows Oklahoma to implement an emissions trading program or other alternative measure in lieu of BART. Among other requirements, such an alternative to BART must achieve greater reasonable progress than would be achieved through the installation and operation of BART. However, Oklahoma did not include such a program as part of its RH SIP, and we cannot require Oklahoma to establish an emission trading program that would support annual emission caps or operational limits on the six BART-subject units. We also note that as a practical matter, there is no longer adequate time to develop and implement such an emissions trading program and meet our consent decree deadline with WildEarth Guardians of December 13, 2011 if we attempted to develop and implement such an emission trading program as part of our action.26 Whether or not existing natural gas-fired power generation capacity in 26 See, WildEarth Guardians v. Jackson, Case No. 4:09-cv-02453CW (N. Dist. Cal.). App. 155 Oklahoma and other parts of the Southwest Power Pool is underutilized has no direct bearing on our SO2 BART determinations. Comment: We received multiple comments from numerous parties concerning the economics of switching from coal-fired to natural gas-fired power generation. These comments focused on a wide range of economic issues, including cost-benefit analysis of one BART compliance alternative over another, future risk to ratepayers due to future maintenance and compliance costs, economic impact of increasing reliance on renewable energy sources, and ancillary benefits to the economy of switching from coal to natural gas or renewable energy sources. Many of the comments we received pertain to the additional economic burden of addressing coal combustion and scrubber waste that would continue to be generated by the six BART-subject coal-fired units if the utilities elect to comply with the BART requirements of the proposed FIP by installing scrubber units, rather than fuel switching. One commenter provided an economic analysis indicating that containment of the coal ash and scrubber waste would cost $180 million in capital investment and $2––$5 million annually for disposal of residuals if the utilities can sell the fly ash, or up to $9 million annually if the fly ash cannot be sold. The commenter further asserts that scrubbing all six of the BARTsubject coal-fired units could generate up to 600,000 tons per year of flue gas desulfurization waste byproducts, the disposal of which could cost an additional $22 million annually. Two commenters have asserted that the power generation capacity of the six App. 156 OG&E and AEP/PSO units can be replaced with the construction of new, modern natural gas-fired combined cycle turbines for less money than would be required to install scrubbers on the coal-fired units to meet BART emission limits. Other comments focused on the likely imposition of future, additional environmental regulatory compliance costs associated with continued firing of coal, such as requirements for new baghouses to control emissions of particulate matter and metals, construction of improved and expanded containment of coal combustion residuals, and carbon emission reductions or sequestration. These commenters noted that attempting to further extend the lives of the six OG&E and AEP/PSO units is a bad investment when such additional controls for other pollutants are foreseeable, and that switching to natural gas power generation would reduce the risk to ratepayers of the eventual cost increases associated with these additional regulatory requirements. Several commenters noted that the six OG&E and AEP/PSO units are approaching the end of their useful lives and that switching to natural gas and renewable energy sources will decrease the risk to ratepayers of increased maintenance costs due to the advanced age of the units. Other commenters, some of whom identified themselves as ratepayers at the affected utilities, indicated that they would be willing to pay an increase in power rates in exchange for power that was generated by cleaner fuels or renewable energy sources. These commenters cited the overall health and environmental benefits that would result from a App. 157 transition away from coal-fired power and expressed their belief that such benefits would outweigh any potential increase in electricity rates. Finally, two commenters suggested that switching to natural gas and/or renewable energy sources would have collateral economic benefits by creating new jobs and providing general economic stimulus in the region. Response: We affirm that each of the sources subject to BART under the FIP can acceptably meet the emission limits in the FIP by switching to natural gas. As the companies evaluate how to satisfy their BART obligations, we encourage them to consider switching from coal to natural gas at the six affected units as this may offer numerous, significant long-term financial and environmental benefits over the option of continued use of coal with additional controls. As was stated in our proposal, we do not wish to dissuade companies from exercising this option. As we discuss elsewhere in our response to comments and Supplemental RTC, we find that a compliance deadline of five years is appropriate for any of the six OG&E and AEP/PSO units that elect to comply with the FIP SO2 emission limit by converting an existing unit to natural gas or replacing it with a new, natural gas-fired unit. Comment: Several commenters expressed concern over the potential rate increases that might result from a switch to natural gas or some form of renewable energy sources and the impact of those rate increases on households with low or fixed incomes. Response: The companies owning each of the sources subject to BART are only required to satisfy the SO2 BART emission limits at those sources. Our action only App. 158 contemplates the reconfiguration of existing units. We have determined that reconfiguration would be cost effective with application of dry and wet scrubbing technology. Though the SO2 BART emission limits may also be met with reconfiguration of the units to burn natural gas, the companies themselves are free to determine whether this option best responds to future customer needs and preferences, including any potential impact on rates. As we state elsewhere in this response to comments and the Supplemental RTC, although we based our BART determination of the use of SO2 dry scrubbers, the owners of the six units in question are free to consider any technology to meet their SO2 BART obligations, including switching to natural gas. We acknowledge the potential benefits that the commenters suggest of switching the units in question to burn natural gas. Renewable energy technology is not a retrofit option for the sources subject to BART and is accordingly outside the scope of our action. Comment: Several commenters have expressed the view that it does not make good economic sense to invest heavily in new control equipment in order to meet BART on units that are so close to retirement. Some of these commenters point out that it makes more sense to invest in new natural gas-fired units instead of converting the existing boilers to burn natural gas, given the size of the investments being considered and the advanced age of the existing coalfired units. Several of the comments focused on the long-term economic benefits of construction of new natural gas- App. 159 fired units over conversion of the existing boilers at the six coal-fired units to meet the BART emission limits. Response The BART guidelines do allow for consideration of the remaining useful life of facilities when considering the costs of potential BART controls. Such a claim would have to be secured by an enforceable requirement. Neither OG&E nor AEP/PSO claimed any such restriction on the operation of these six units and Oklahoma did not submit any enforceable document for action by us. Consequently, we assumed a remaining useful life of 30 years in our BART analysis. If OG&E and/or AEP/PSO decide the units in question have a shorter useful life such that installing scrubbers is no longer cost effective, and are willing to accept an enforceable requirement to that effect, a revised BART analysis could be submitted by the plant(s) in question and our FIP could be re-analyzed accordingly. Similarly, we could also review a revised SIP submitted by ODEQ. Comment: Numerous commenters expressed broad support for transitioning away from coal and other fossil fuels to sources of energy that are completely renewable, such as wind and solar-generated power. These commenters recommend that the BART-subject units should be replaced with wind-powered units where possible and that natural gas should be used for power generation during periods of low wind yield. One of the commenters notes that Oklahoma and other parts of the Southwest Power Pool (SPP) have enormous potential for wind farm development and that as of July 2010 the SPP transmission interconnection queue had 111 wind generation App. 160 projects totaling over 20,000 MW and an additional 7,470 MW of incremental wind development. Comments received on this subject also noted that wind power can be developed at relatively low costs and that the money the utilities currently spend on the importation of coal and handling the byproducts of its combustion would be better spent on construction of additional wind generating capacity. Response: Renewable energy technology is not a retrofit option for the sources subject to BART and is therefore outside the scope of our SO2 BART determination. We do generally acknowledge that many kinds of renewable energy do not produce hazecausing pollutants, and transitioning to those sources of energy could lead to visibility improvements. Comment: We received opinions and data from four commenters expressing support for increased energy efficiency efforts as a technique for lowering power demand and therefore reducing the combustion of fossil fuels and its impact on the environment. One of these commenters noted that the affected utilities have begun some energy efficiency programs and that with increased effort they should be able to realize the successes of other programs elsewhere in the country that have seen cumulative reductions in annual power consumption of 5––8 percent since 2004. The commenter notes that OG&E, in particular, should be able to reduce power demand by up to 1,200 GWh/year and 2,100 GWh/year after five and ten years, respectively, at an annual reduction goal of one percent, or as much as 1,800 GWh/year and 3,100 GWh/year after five and ten years, respectively, at an annual reduction goal of one and a half percent. App. 161 Response: While not specifically within the scope by our SO2 BART determination or our approval of other aspects of the state’’s RH SIP, we acknowledge that efficiency programs that reduce reliance on sources of haze-causing pollutants may promote visibility improvements. Comment: OG&E states that if it is required to decide whether to install scrubbers or retire and replace electric generating units with natural gas on roughly the same time frame, the economic analysis suggests that rate increases to customers will be lower with scrubbers. Installation of scrubbers is projected to cost more than $1.5 billion. OG&E is concerned that with this type of capital investment, it would be locked economically into maximizing the use of its coal-fired units for the foreseeable future. OG&E states the agreement outlined by ODEQ in the SIP (and rejected by EPA) would reduce ““the cumulative SO2 emissions from Sooner Units 1 and 2 and Muskogee Units 4 and 5 [to] approximately fifty-seven percent (57%) less than would be achieved through the installation and operation of Dry FGD with SDA at all four (4) units.”” OG&E states it should have the flexibility to take advantage of evolving technologies and to utilize these local clean energy sources at its plants in the future, while achieving the same (or better) reduction in impact on visibility. OG&E states EPA’’s failure to consider these issues in the proposal is short-sighted, and arbitrary, capricious and contrary to applicable law. Response: We find the approximately $1.2 billion cost claimed by OG&E in its BART analysis (referenced above as $1.5 billion) for the installation of SO2 dry App. 162 scrubbers is in error. As discussed elsewhere in our response to comments and Supplemental RTC, based on our Option 1 and Option 2 analyses, we find the total project costs to range between $290,418,007 to $299,400,007 for Sooner Units 1 and 2, and from $298,818,917 to 289,791,940 for Muskogee. Further, as we also discuss in our proposal, although we based our SO2 BART determination on the basis of dry SO2 scrubbers, OG&E is free to employ other technologies to meet this limit, including switching to natural gas, as long as that switch is completed in the same BART timeframe. We discuss the BART compliance deadline in the response to another comment. Comment: A commenter stated we failed to consider ““the costs of compliance”” of converting the six coal-fired generating units to natural gas. Without any explanation, contends OIEC, we proposed that these generating units could be converted to natural gas ““as a means of satisfying their BART obligations.* * *”” 76 FR 16168, at 16194. The commenter states we failed to consider the costs of compliance of conversion to natural gas, as required by the CAA section 169A(g)(2), and the BART Guidelines, Part 51, Appendix. Y(IV)(D)(4)(a). The commenter states the FIP should therefore be withdrawn. Response: The commenter’’s reference to our proposal27 is fully reproduced as follows: Should OG&E and/or AEP/PSO elect to reconfigure the above units to burn natural gas, as a means of satisfying their BART obligations 27 76 FR 16168, at 16194. App. 163 under section 51.308(e), that conversion should be completed by the same timeframe. We invite comments as to, considering the engineering and/or management challenges of such a fuel switch, whether the full 5 years allowed under section 308(e)(1)(iv) following the effective date of our final rule would be appropriate. Under the RHR,28 we cannot, and did not, evaluate the costs associated with switching the six OG&E and AEP/PSO units over to natural gas for BART. However, after conducting the BART analysis and adopting of emissions limits, alternatives to installing control technologies may achieve the same emission limits. We are open to alternative mechanisms to achieve the BART emissions limits we adopted. As stated in our proposal, we merely afforded OG&E and/or AEP/PSO the opportunity to switch to natural gas as a means of satisfying BART. We also indicated we were willing to consider comments to extend the BART compliance timeframe to the full amount of time allowed under the RHR to accommodate that conversion. Although we based our BART determination of the use of SO2 scrubbers, the six units in question are free to consider any technology or alternative mechanism to meet their SO2 BART obligations. J. Comments Arguing Our Proposal Would Hurt the Economy and/or Raise Electricity Rates Comment: Several commenters expressed concern about adverse effects of electrical bill increases, stating 28 70 FR 39104, at 39164: ““note that it is not our intent to direct States to switch fuel forms, e.g. from coal to gas.”” App. 164 that analyses prepared by the state’’s utilities, business groups and the Oklahoma Corporation Commission estimate our proposal could increase utility bills in Oklahoma significantly, with some estimates as high as 30 percent. Some commenters stated that the rate increase would result in decreased business investment in Oklahoma; while others stated that it will hurt existing businesses, local governments, and families already struggling from the recession. Several commenters noted that the rate increase will have a disproportionate adverse impact on senior citizens and the disadvantaged, especially individuals living on fixed incomes. Commenters urged us to consider the cost implications of our proposal as we balance the goals of the CAA with the economic impact on consumers, communities, and businesses. Specifically, one commenter stated that installation of scrubber technologies on aging coal-fired facilities may not be the most cost-effective or environmental approach. Several commenters ask EPA to consider all of the alternatives available, including switching to natural gas over a longer timeframe. One commenter further stated that EPA’’s proposal is not cost effective and does not significantly improve visibility. Commenters urged EPA to adopt the Oklahoma State plan. A commenter that supported the proposal stated that while the FIP could cause rates to increase somewhat, Oklahoma has the eighth lowest average electricity rates in the country, rates are higher in neighboring states, and the difference in rates may result from the fact that other states have emission controls on a higher percentage of their coal plants. Response: The federal regulations implementing the CAA’’s BART provisions require that we evaluate App. 165 (1) cost of compliance, (2) the energy and non-air quality environmental impacts of compliance, (3) any existing pollution control technology in use at the source, (4) remaining useful life of source, and (5) degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. 40 CFR 51.308(e)(1)(ii)(A). After a careful cost review, we have determined that benefits in visibility from implementing our proposal outweigh the increase in costs for the facilities. As discussed in our proposal, we disagree with OG&E’’s and AEP/PSO’’s cost estimate for installing scrubbers on the six units addressed by our FIP. After careful review of information provided during the public comment period, we revised our calculation of the total project cost for the four OG&E units from our proposed range of approximately $312,423,000 to $605,685,000, to our final range of approximately $589,237,000 to $607,461,000. We made no changes to the cost basis for the two AEP/PSO units from our proposal. As such, the associated cost investment for AEP/PSO is $274,100,000. In light of the visibility benefits we predict will occur, we consider this to be cost effective. We take our duty to estimate the cost of controls very seriously, and make every attempt to make a thoughtful and well informed determination. We note that our cost estimate, being about half that of OG&E’’s will result in significantly less costs being passed on to rate payers. We also note that our FIP allows for any of the six units to switch to natural gas within five years of this final action instead of installing the control technology. App. 166 K. Comments Arguing Our Proposal Would Help the Economy Comments: We also received comments that the proposed FIP would help the economy in a variety of ways. One commenter stated that environmental regulations like the RHR improve the economy and create jobs; and industry always finds a way to manage the cost of implementation. One commenter states that cleaner air will boost Oklahoma’’s productivity and job creation. Response: Although, we did not consider the potential positive benefits to local economics in making our decision today, we do acknowledge that improved visibility may have a positive impact on tourism. Also, installing the controls required by the BART determination on the six units will take three years or longer to complete. These projects will require wellpaid, skilled labor that can potentially be drawn from the local area, which would seem to benefit the economy. Finally, as we have noted elsewhere in our response to comments, although our action concerns visibility impairment, this action may also result in significant improvements in human health. Improved human health will reduce the healthcare costs and reduce the number of missed school and work days in the community. L. Comments on Health and Ecosystem Benefits and Other Pollutants Comments: Several commenters state that pollutants that cause visibility impairment also harm App. 167 public health. Specifically, commenters assert the following: RH pollutants include NOX, SO2, PM, ammonia, and sulfuric acid. NOX is a precursor to ground level ozone, which is associated with respiratory diseases, asthma attacks, and decreased lung function. NOX also reacts with ammonia, moisture, and other compounds to form particulates that can cause and worsen respiratory disease, aggravate heart disease, and lead to premature death. Similarly, SO2 increases asthma symptoms, leads to increased hospital visits, and can form particulates that aggravate respiratory and heart diseases and cause premature death. Both NOX and SO2 cause acid rain. PM can penetrate into the lungs and cause health problems, such as premature mortality, lung disease, aggravated asthma, chronic bronchitis, and heart attacks. Commenters cite to EPA’’s estimates that in 2015, full implementation of the RHR nationally will prevent 1,600 premature deaths, 2,200 non-fatal heart attacks, 960 hospital admissions, and over 1 million lost school and work days. The RHR will result in health benefits valued at $8.4 to $9.8 billion annually. More than 100,000 children and 365,000 adults are diagnosed with asthma in Oklahoma, and hospitalizations in Oklahoma due to asthma cost roughly $57.9 million in 2007 alone. Commenters also cite to a Clean Air Task Force finding that the six units at issue in the proposed rule annually cause approximately 118 deaths, 181 heart attacks, 2,037 asthma attacks, 86 hospital App. 168 admissions, 74 cases of chronic bronchitis, and 129 emergency room visits. Some commenters also relay personal stories of the health impacts on themselves and their families from the emissions at issue. One commenter is disappointed that the air quality in Oklahoma is so poor that the ODEQ often warns active adults to avoid prolonged outdoor exposure. She notes that ozone action days prevent children from playing outside in the summer. Several children have been hospitalized due to asthma and other illnesses that the commenters attribute to the emissions at issue. One commenter contends that many people who are impacted by this rulemaking are not aware of the rulemaking process, or their rights under that process. Commenters further state that it is EPA’’s responsibility to protect the air quality and prevent these negative health effects. Several commenters also assert that NOX and SO2 emissions from coal plants harms crops like pecans, barley, and oats, which puts the livelihoods of local farmers at risk, impacts the health of those who consume the contaminated food, and increases the cost of food. Some commenters want this rulemaking to address health issues. One commenter states that, while the RHR was designed to provide redress for visibility impairment, the BART Guidelines expressly provide for the consideration of non-air quality environmental impacts in step four of the five-step BART process. This consideration includes the environmental impact on human health. App. 169 One commenter states that the power plants have had plenty of time to change operations to comply, but they have failed to do so. Several commenters assert that Oklahoma is unable to properly manage water and air pollution because special interest groups trump science. Another commenter states that coal pollution is devastating tourism and wildlife in Oklahoma. One commenter states that cleaner air will improve the health of its citizens. Some commenters assert that customers are subsidizing the cost of electricity with their health, lives, and livelihoods. One commenter stated that the increase in electricity costs is offset by reducing the healthcare costs to the community to treat illnesses and deaths caused by air pollution from the plants. Another commenter points out that power plants are also built near the most vulnerable and underserved populations in the state, based on the argument that the plants will bring needed jobs. One commenter concludes that it is unfair and unethical to hold citizens hostage to the idea that they must choose between electricity and good health. Several commenters feel that it is appropriate for industry to bear the burden of the cost, rather than pass it on to citizens of the state in the form of healthcare costs. These commenters are amenable to paying higher electricity rates in exchange for healthier air and water. Several commenters request that EPA impose the strongest possible regulation of emissions and enforcement of the CAA. Another commenter notes that President Nixon created EPA to protect the environment and the CAA was passed to protect air quality in our national parks and wilderness areas. President Reagan’’s acid rain program cost less than industry or EPA estimated; and App. 170 hopefully, installing scrubbers on these coal plants will also cost less than estimated. Further, the CAA allows EPA to limit sulfur oxides, nitrogen dioxides, organic compounds, and particulates to ensure the quality of the air in the region. Several commenters state that coal pollutes throughout the process during extraction, burning, and disposal. One commenter states that the true cost of coal is the cost of its transportation, remediation of coal pollution, and lost tourism and bad public relations in states where coal production occurs through mountaintop removal. Many commenters recommend that Oklahoma convert to more efficient sources of energy such as natural gas, wind, and solar power. One commenter asserts that he suffered from severe childhood asthma caused by allergies before the coalfired power plants were built. He states that affordable electricity from the plants allows him to keep his windows closed, thereby preventing allergens from entering his home. Response: We appreciate the commenters’’ concerns regarding the negative health impacts of emissions from the six units at issue. We agree that the same NOX emissions that cause visibility impairment also contribute to the formation of ground-level ozone, which has been linked with respiratory problems, aggravated asthma, and even permanent lung damage. We also agree that SO2 emissions that cause visibility impairment also contribute to increased asthma symptoms, lead to increased hospital visits, and can form particulates that aggravate respiratory and heart diseases and cause premature death; and that both NOX and SO2 cause acid rain. We agree that the same App. 171 PM emissions that cause visibility impairment can be inhaled deep into lungs, which can cause respiratory problems, decreased lung function, aggravated asthma, bronchitis, and premature death. We agree that these pollutants can have negative impacts on plants and ecosystems, damaging plants, trees, and other vegetation, and reducing forest growth and crop yields, which could have a negative effect on species diversity in ecosystems. Therefore, although our action concerns visibility impairment, we note the potential for significant improvements in human health and the ecosystem. The CAA states that the non-air quality environmental impacts of compliance are a consideration in determining BART. See CAA Section 169A(g)(2). The BART Guidelines allow for the consideration of non-air quality environmental impacts under 40 CFR 51, Appendix Y(IV)(D)(j). See also, 70 FR 39104, at 39169. However, this BART factor generally is considered in order to determine if a control option that is otherwise technically feasible should be eliminated due to adverse environmental impacts. Such impacts could include solid or hazardous waste generation and discharges of polluted water as a result of the control device. Although we may note potential health benefits from the reduction of air pollutants due to the installation of a BART control, we do not consider them as part of the BART determination. While we received many comments concerning health impacts from the ongoing operations of BART-eligible sources, we received no comments asserting that dry and wet scrubbers should be differentiated or eliminated as compliance options based on non-air quality environmental impacts. App. 172 Although we appreciate the commenters’’ encouragement that we adopt even stricter standards, after considering all the comments we received, as we have stated elsewhere in this notice, we believe that the standards proposed in our proposal establish BART and will prevent visibility impairment from the six units. Issues that the commenters raise about the effect of EPA’’s action on the cost of electricity are addressed elsewhere in this notice. Additionally, comments that recommend that the six units switch to natural gas or other sources of renewable energy are addressed elsewhere in this notice. Comments: Several commenters note that coal-plant emissions contain other toxins including mercury, lead, cadmium, chromium, dioxins, formaldehyde, arsenic, radioactive isotopes, oxide, and radon gas. Another commenter is concerned that the toxicity of the pollutants in regional haze is higher in close proximity to the source of emissions. Specifically, several commenters state that poor reclamation of coal ash from AEP’’s Shady Point power plant causes negative health impacts in Bokoshe, Oklahoma. These commenters are concerned about the health effects of fly ash because they state it contains arsenic, mercury, lead, cadmium, and other toxins. They describe the project as consisting of transporting coal ash from the plant to an abandoned lead mine in Bokoshe. Commenters claim that the result is a fifty foot wall of toxic coal ash at the reclamation site in Bokoshe. Commenters state that pollution from the reclamation project has damaged property and people’’s health. They state that fugitive emissions from the App. 173 trucks and the reclamation site run off into the ground water, polluting drinking water supplies. One commenter also states that fly ash has been used in Oklahoma as repair material for county roads. Commenters state that sixteen to twenty families living nearby have cancer, children have asthma, and calves in the area are stillborn. One commenter states that EPA’’s proposal to put scrubbers on the units at issue will help address asthma, but these scrubbers will cause emissions of toxic fly ash. Several commenters are concerned that the mercury, chromium, and arsenic from the coal-fired power plants are contaminating food, primarily fish. One commenter contends that these chemicals are carcinogenic and bioaccumulate. As a result, they state, some fish in Oklahoma have high levels of toxic materials and cannot be consumed. Commenters note that mercury contamination is so extreme that larger fish species are unsafe for pregnant women to eat. One commenter states that mercury is a neurotoxin that negatively affects a child’’s ability to talk, walk, read, and learn. Several commenters point out that ODEQ has issued advisories that prohibit eating fish from certain lakes because the mercury content is dangerously high. One commenter further states that sixteen out of fifty of the lakes in Oklahoma have elevated levels of mercury. Response: Although we appreciate the commenters’’ concerns regarding the potential negative health impacts from toxic emissions from the six units at issue, we note that we are not quantifying any toxic emissions that may be emitted, and such emissions are not considered to be visibility impairing pollutants. App. 174 Therefore, consideration of the toxic emissions is outside the scope of this rulemaking under the RHR. However, please note that other provisions of the CAA, as well as other environmental statutes and regulations address toxic emissions, such as the ones noted here. EPA implements such programs to protect human health and the environment from the negative impacts of these pollutants, and Oklahoma’’s SIP is required to include provisions consistent with these Federal requirements to the extent that they are applicable. Comment: One commenter mentions the impacts of the transport of emissions from existing and planned coal plants in Texas, stating that sixty percent of mercury pollution in Oklahoma comes from Texas. He requests that EPA accelerates mercury testing in Oklahoma’’s land and lakes. Response: While we understand the commenter’’s concern with the impacts of transport emission from Texas on water bodies in Oklahoma, mercury testing of water bodies is outside the scope of our action. Mercury is not considered a visibility impairing pollutant; it is an air toxic regulated under CAA requirements that are distinct from the RHR and CAA section 110(a)(2)(D)(i)(II). Comments: Several commenters discuss the impact of coal power on climate change. One commenter also notes that we should regulate CO2 because ninetyseven percent of scientists agree that it is causing climate change. He contends that coal fired power plants are contributing to climate change, stating that the CO2 level has risen from 280 ppm during the preindustrial age to 380 ppm today. He cites the IPCC and App. 175 others who state that the CO2 level should not exceed 350 ppm. He also discusses the increasing temperatures and potential for sea level rise in the near future. The commenter states that we need to address climate change now. Response: While we understand the commenters’’ concerns with respect to climate change, consideration of climate change is outside the scope of our action on the RHR. While CO2 is a greenhouse gas (GHG), it is not considered a visibility impairing pollutant. However, EPA implements regulations that address GHGs in order to protect the public and the environment from the negative impacts of climate change. Additionally, Oklahoma’’s SIP is required to include provisions consistent with those Federal requirements. M. Miscellaneous Comments Comment: OG&E states that we found a defect in Oklahoma’’s Long Term Strategy (LTS) because CENRAP modeling assumed the presumptive SO2 BART limit (0.15 lb/mmBtu) for OG&E’’s Sooner and Muskogee facilities, which was not secured by Oklahoma in its SIP. OG&E states we reasoned that the proposed FIP was necessary to cure these defects. OG&E asserts we may not pre-determine the BART SO2 emissions limit based on assumptions made during regional modeling, but the emissions limit should be determined based on the five statutory factors as applied to an individual facility. Further, OG&E states our reasoning with respect to the Oklahoma LTS is in error. When setting reasonable progress goals for their own Class I areas, OG&E App. 176 states, the states are authorized to consider the same five statutory factors that are used in determining BART, including the costs of additional controls. OG&E states that Oklahoma did not specify additional SO2 controls for the Sooner and Muskogee units as part of Oklahoma’’s LTS for the Wichita Mountains. OG&E notes that for Class I areas in other states, a state must ensure that it has included in its LTS all measures needed to achieve its apportionment of emission reduction obligations agreed upon through the regional planning process. 40 CFR 51.308(d)(2)(ii). OG&E states that ODEQ found that its LTS required no further controls for Oklahoma sources because emissions from Oklahoma were found (through the regional planning process) to impair visibility at all relevant Class I areas other than Wichita Mountains only insignificantly. Thus, OG&E reasons, the Oklahoma LTS is consistent with the agreements reached during regional planning. OG&E states we failed to justify, or explain, our basis for assuming that the regional planning process would have come to a different conclusion concerning Oklahoma’’s impact on other states’’ Class I areas if a different SO2 emission rate had been assumed for the Sooner and Muskogee units in question. Response: We disagree with OG&E’’s assertion that Oklahoma’’s decision not to require controls for the six OG&E and AEP/PSO units is consistent with the RH requirements for the LTS, section 51.308(d)(3)(ii), which requires: Where other States cause or contribute to impairment in a mandatory Class I Federal area, the State must demonstrate that it has App. 177 included in its implementation plan all measures necessary to obtain its share of the emission reductions needed to meet the progress goal for the area. If the State has participated in a regional planning process, the State must ensure it has included all measures needed to achieve its apportionment of emission reduction obligations agreed upon through that process. Oklahoma did engage in a regional planning process. This regional planning process included a forum in which state representatives built emission inventories that assumed that specific pollution sources would be controlled to specific levels. This included assumptions that the six OG&E and AEP/PSO units would be controlled to presumptive BART emission levels for SO2. Visibility modeling projections subsequently assumed those emission reductions. However, Oklahoma, in its subsequent RH SIP, did not include these promised reductions on which the other states are presently relying. We note the CENRAP RPO process was open and representatives from industry occasionally attended CENRAP meetings and had an opportunity to engage in this process. ODEQ engaged in consultations under 51.308(d)(3)(i), which requires that where the State has emissions that are reasonably anticipated to contribute to visibility impairment in any mandatory Class I Federal area located in another State or States, the State must consult with the other State(s) in order to develop coordinated emission management strategies. The State must consult with any other State having emissions that are reasonably anticipated to contribute App. 178 to visibility impairment in any mandatory Class I Federal area within the State. All states that engaged in these consultations were involved in the discussions leading up to, and the actual construction of the emission inventories and the modeling strategy. These LTS consultations therefore assumed OG&E’’s Sooner and Muskogee sources would be controlled to the presumptive limit levels and made decisions regarding whether additional controls to address LTS were needed on that basis. Thus, we are disapproving Oklahoma’’s LTS. Furthermore, and notwithstanding the above LTS discussion, we disagree with OG&E’’s assertion that our BART analysis of the six OG&E and AEP/PSO units is due to the CENRAP modeling. As we discussed in our proposal, we arrived at our proposed BART determination for the six units in question after performing the BART analysis required under the RHR. Comment: AEP/PSO commented that we should clarify that new monitoring systems proposed under section 52.1923(e) do not need to be installed for both Unit 3 and Unit 4 of the Northeastern plant if the same fuel is used for both units. Instead, they reason, stack emissions should be apportioned to the units based on unit to stack load ratios. AEP/PSO claims the equipment necessary to report emissions for each unit individually will add approximately $250,000 to the cost to comply, and provides no better data on emissions to the atmosphere. Response: We are affirming that we are in fact requiring that the monitoring described in section App. 179 52.1923(e) must be installed separately for each of Units 3 and 4 of the AEP/PSO Northeastern plant even though the same fuel is used for both units. We do not find that it is proper to calculate the emissions of each unit based on its load ratio, as individual SO2 scrubbers will likely have slightly different performance characteristics and we need to ensure that both units’’ scrubbers are working properly by monitoring the emissions unit by unit. Comment: AEP/PSO believes there is a conflict between the language in section 52.1923(d) and (e). Section 52.1923(d) states that if a valid SO2 pounds per hour or heat input is not available for any hour for a unit, that heat input and SO2 pounds per hour shall not be used in the calculation of the 30-day rolling average for SO2. Section 52.1923(e) states that when valid SO2 pounds per hour, or SO2 pounds per million Btu emission data are not obtained because of continuous monitoring system breakdowns, repairs, calibration checks, or zero and span adjustments, emission data must be obtained by using other monitoring systems approved by the EPA to provide emission data for a minimum of 18 hours in each 24 hour period and at least 22 out of 30 successive boiler operating days. Response: We do not see a conflict between the language in sections 52.1923(d) and (e). Paragraph (d) refers to short term, discrete data acquisition problems and paragraph (e) refers to more serious problems that may arise due to fundamental underlying problems with the monitoring system. App. 180 Comment: One commenter called for an integrated and comprehensive strategy for EGUs to meet CAA requirements, noting that EGU emissions are subject to the RHR, the PM2.5 NAAQS, and the National Emissions Standards for Hazardous Air Pollutants. The commenter stated that to effectively address impacts to human health and RH caused by EGU emissions, the FIP or SIP should require (1) SCR to control NOX, (2) wet scrubbers to control SO2, and (3) wet electrostatic precipitators to control condensable particulate matter and acid mists. The commenter also asked us to reconsider our proposal to accept ODEQ’’s NOX BART determination, because (1) according to our proposal additional NOX reductions would achieve significant improvement in visibility over baseline, (2) Nitrate particulates from EGUs are primarily responsible for the majority of visibility impairment during winter days, and (3) the full benefit of wet scrubber controls may not be achieved unless BART controls on NOX is also required. Concerning SO2, the commenter expressed concern that the proposal would ““approve”” a dry scrubber system, along with an older electrostatic precipitator at the OG&E Sooner facility that would achieve poor control of PM2.5 emissions. The commenter added that the proposed rule does not provided adequate information to allow the public to understand and compare control measures or to comprehend the extent of underperformance of PM2.5 controls. Another commenter requested additional controls and monitoring for ammonia and sulfuric acid. Specifically the commenter (1) requested that we set emission limits for ammonia and sulfuric acid mist, similar to those proposed for the San Juan Generating App. 181 Station in New Mexico (76 FR 491), (2) stated their support for requiring continuous emissions monitors to monitor ammonia, and (3) urged us to require stack testing for sulfuric acid on a more frequent basis than annual monitoring. Response: The purpose of our plan is to address the CAA BART requirements. Our evaluation found that: •• The NOX controls adopted by the state meet the CAA BART requirements; •• The SO2 BART controls we proposed in our FIP, in addition to the state adopted NOX controls, would lead to significant improvement in visibility and meet the CAA BART requirements; •• Additional NOX controls would not be cost effective; and •• Additional pollutant controls are not needed to meet the CAA BART requirements. Regarding the request for ammonia and sulfuric acid mist emission limits and monitoring, we did propose ammonia and sulfuric acid limits and monitoring, as part of our New Mexico RH FIP for the San Juan Generating Station. 76 FR 491. We did this because we were concerned about the potential for ammonia slip, as a result of the operation of Selective Catalytic Reduction (SCR), and the potential for the growth in sulfuric acid emissions if they were not limited in an enforceable manner. As explained in our response to comments in that action, we ultimately determined that neither an ammonia limit, nor App. 182 ammonia monitoring was warranted.29 We did, however, limit sulfuric acid emissions, verified by annual stack testing due to the potential for visibility impairment from increased sulfuric acid emissions associated with operation of SCR. These issues are not applicable here, as our BART FIP is concerned with the reduction of SO2, which is not controlled by SCR, and our visibility modeling does not indicate the need to control or monitor sulfuric acid or ammonia emissions. Comment: One commenter stated that by mandating scrubbers on coal plants that we are trying to phase out does not make sense. Another commenter asked why switching to low sulfur coal is not considered a viable alternative instead of mandating installation of expensive wet gas scrubbers. A third commenter stated that the EPA continues to bog down electricity producers with burdensome paperwork and legal uncertainty and that the EPA RHR is a perfect example of the EPA’’s lack of economic reality. Response: We are not attempting to phase out the Oklahoma coal plants that are subject to our FIP. The purpose of our FIP is to control SO2 emissions from six Oklahoma EGUs that contribute to RH in order to meet the CAA BART requirements. To that end we are setting emissions limits for SO2. We are not requiring certain control technologies or fuel sources. As discussed earlier, we used the CAA’’s BART evaluation criteria for our plan and found that it is reasonable and realistic. The paperwork required will ensure compliance with the BART FIP. 29 76 FR 52388, at 52407. App. 183 Comment: One commenter expressed his view that citizens should ask EPA to set and enforce regulations for haze because the state regulations were inadequate. Another commenter stated that we should reject lower standards suggested by others. Response: We agree with the commenter that Oklahoma’’s RH SIP was inadequate in its control of SO2 from the six OG&E and AEP/PSO units. We find that our FIP will require the proper amount of SO2 control in order to comply with the RHR. Comment: A request was submitted that we hold a public hearing on our proposal in Tulsa, Oklahoma. Response: Originally we scheduled one public hearing in Oklahoma City. In response to the request we added a second hearing in Tulsa on April 14, 2011. The transcripts of both public hearings are available in the docket. Comment: One commenter asked us to work with ODEQ and the electrical power providers to develop a cost effective plan. Response: We find that the SO2 controls required by our FIP are, for the reasons discussed elsewhere in our response to comments and Supplemental RTC, cost effective. We are, however, willing to work with ODEQ and others to develop a SIP that could replace our FIP. Such a SIP will need to meet the CAA and EPA’’s RH regulations and be consistent with EPA’’s guidance. Comment: One commenter supported our proposal’’s (1) determination that Oklahoma’’s SO2 BART limits do not meet the RH regulations, (2) analysis of the visibility improvement resulting from BART controls, App. 184 (3) determination that low NOX burners are appropriate as BART, and (4) determination that existing electrostatic precipitators and a 0.1 lbs/MMBtu emissions limit is appropriate as BART for particulate matter. Response: We appreciate the comments. Comment: Comments were received expressing concern over other sources of air pollution, such as landfills, coal-fired power plants, the Tar Creek superfund site and sources in Texas. Response: While we understand the commenter’’s concern with the impacts of other sources of pollution, the scope of this action is limited to assessing whether certain elements of the Oklahoma RH SIP meet the RH requirements of the CAA, including BART, and addressing any deficiencies identified. We note also that other state and federal statutes and regulations address other sources of air pollution, such as those referenced by the commenters, to protect human health and the environment from the negative impacts of these pollutants. Comment: Two commenters provided questions at the Oklahoma City public hearing. Several questions relate to Class 1 areas, such as: designation of Class 1 areas; location of Class 1 areas in relation to the six units and other coal-fired units; frequency, degree, and season of visibility impact in Class 1 areas; and tourism at the Class 1 areas. Other questions concern cost of compliance by the six units, such as: annual and total cost; cost and benefit analysis of comparing the cost of compliance to ““visitor impact days””; economic impacts to the region; and EPA’’s authority to App. 185 implement the FIP. Finally, some questions concern the Wichita Wildlife Refuge specifically and contemplate sources of haze impacting that Class 1 area, other than the six units. Response: In general, answers to these questions are: (1) Found in our proposal or in supporting documents for our proposal, (2) furnished in response to other comments, or (3) not a necessary or relevant consideration for our action. For responses to these comments, please see the ““Addendum Responding to Questions Received”” available in the electronic docket for this rulemaking. Comment: We received comments not related to the proposal. These included comments on: •• Enforcement by EPA and ODEQ; •• A RH educational plan; •• Emissions from the LaFarge cement company; and •• Eliminating coal as a source of energy. Response: While these and other comments may be important topics for discussion, we are not addressing these topics as they are outside the scope of our rulemaking. IV. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review This action finalizes a source-specific FIP for six units at coal-fired power plants in Oklahoma (OG&E App. 186 Sooner Plant Units 1 and 2, OG&E Muskogee Plant Units 4 and 5, and AEP/PSO Northeastern Plant Units 3 and 4). This type of action is exempt from Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011). B. Paperwork Reduction Act This action does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. Burden is defined at 5 CFR 1320.3(b). Under the Paperwork Reduction Act, a ““collection of information”” is defined as a requirement for ““answers to * * * identical reporting or recordkeeping requirements imposed on ten or more persons * * * .”” 44 U.S.C. 3502(3)(A). Because the FIP only applies to six units at three power plants (OG&E Sooner Plant, OG&E Muskogee Plant, and AEP/PSO Northeastern Plant) the Paperwork Reduction Act does not apply. See 5 CFR 1320(c). C. Regulatory Flexibility Act The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today’’s rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business App. 187 Administration’’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. After considering the economic impacts of this action on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. The FIP for the OG&E Sooner Plant, the Muskogee Plant, and the AEP/PSO Northeastern Plant being finalized today does not impose any new requirements on small entities. See Mid-Tex Electric Cooperative, Inc. v. FERC, 773 F.2d 327 (D.C. Cir. 1985). D. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531––1538, requires Federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector. This rule does not contain a Federal mandate that may result in expenditures of $100 million or more, adjusted for inflation, for state, local, and tribal governments, in the aggregate, or the private sector in any one year. Our cost estimate indicates that the total annual cost of compliance with this rule is below this threshold. Thus, this rule is not subject to the requirements of sections 202 or 205 of UMRA. This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory App. 188 requirements that might significantly or uniquely affect small governments. This rule contains regulatory requirements that apply only to six units at coal-fired power plants in Oklahoma (OG&E Sooner Plant Units 1 and 2, OG&E Muskogee Plant Units 4 and 5, and AEP/PSO Northeastern Plant Units 3 and 4). E. Executive Order 13132: Federalism This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This action merely prescribes EPA’’s action to address the state not fully meeting its obligation to prohibit emissions from interfering with other states measures to protect visibility. Thus, Executive Order 13132 does not apply to this action. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and state and local governments, EPA specifically solicited comment on the proposed rule from state and local officials. F. Executive Order 13175: Consultation Coordination With Indian Tribal Governments and This final action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 6, 2000), because the action EPA is taking neither imposes substantial direct compliance costs on tribal governments, nor preempts tribal law. Therefore, the requirements of section 5(b) and 5(c) of the Executive Order do not apply to this rule. Consistent with EPA policy, EPA nonetheless provided outreach to App. 189 Oklahoma Tribes on several occasions in March and April 2011, and offered consultation regarding this action. EPA did not receive any requests for consultation on this rule. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5––501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because it implements specific standards established by Congress in statutes. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not a significant regulatory action under Executive Order 12866. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (““NTTAA””), Public Law 104––113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. App. 190 NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. This rule would require the affected units at the OG&E Sooner Plant, the Muskogee Plant, and the AEP/PSO Northeastern Plant to meet the applicable monitoring requirements of 40 CFR part 75. Part 75 already incorporates a number of voluntary consensus standards. Consistent with the Agency’’s Performance Based Measurement System (PBMS), Part 75 sets forth performance criteria that allow the use of alternative methods to the ones set forth in Part 75. The PBMS approach is intended to be more flexible and cost effective for the regulated community; it is also intended to encourage innovation in analytical technology and improved data quality. At this time, EPA is not recommending any revisions to Part 75; however, EPA periodically revises the test procedures set forth in Part 75. When EPA revises the test procedures set forth in Part 75 in the future, EPA will address the use of any new voluntary consensus standards that are equivalent. Currently, even if a test procedure is not set forth in Part 75, EPA is not precluding the use of any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the performance criteria specified; however, any alternative methods must be approved through the petition process under 40 CFR 75.66 before they are used. App. 191 J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994), establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. EPA has determined that this rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low-income population. Our FIP limits emissions of SO2 from six units at coal-fired power plants in Oklahoma (OG&E Sooner Plant Units 1 and 2, OG&E Muskogee Plant Units 4 and 5, and AEP/PSO Northeastern Plant Units 3 and 4). In addition to our FIP, we also approve SIP elements that also limit the emission of other pollutants, including PM and NOX. K. Congressional Review Act The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory App. 192 Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this action and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This action is not a ““major rule”” as defined by 5 U.S.C. 804(2). This rule will be effective on January 27, 2012. L. Judicial Review Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by February 27, 2012. Pursuant to CAA section 307(d)(1)(B), this action is subject to the requirements of CAA section 307(d) as it promulgates a FIP under CAA section 110(c). Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. See CAA section 307(b)(2). List of Subjects in 40 CFR Part 52 Air pollution control, Environmental protection, Best available retrofit technology, Incorporation by App. 193 reference, Intergovernmental relations, Interstate transport of pollution, Nitrogen dioxide, Ozone, Particulate matter, Regional haze, Reporting and recordkeeping requirements, Sulfur dioxide, Visibility. Dated: December 13, 2011. Lisa P. Jackson, Administrator. For the reasons set out in the preamble, title 40, chapter I, of the Code of Federal Regulations is amended as follows: PART 52——[AMENDED] # 1. The authority citation for part 52 continues to read as follows: Authority: 42 U.S.C. 7401 et seq. Subpart LL——[Amended] # 2. Section 52.1920 is amended as follows: # a. The table in paragraph (c) is amended by adding in sequential order under ““Subchapter 8. Permits for Part 70 Sources”” a new heading for part 11 and a new entry for ““(252:100:8––70 to 252:100:8––77)””. # b. The first table in paragraph (e) is amended by adding at the end a new entry for ““Interstate transport NAAQS for the 1997 ozone and PM2.5 (Noninterference with measures required to prevent significant deterioration of air quality or to protect visibility in any other State)””, immediately followed by an entry for ““Regional haze SIP””. ““ # c. The second table in paragraph (e) entitled ““EPA Approved Statutes in the Oklahoma SIP”” is amended by removing the entry for ““Interstate transport for the App. 194 1997 ozone and PM2.5 NAAQS.”” The amendments read as follows: § 52.1920 Identification of plan. ***** (c) * * * (252:100:8––70 to 252:100:8––77) * * * State effective date * EPA approval date Visibility Protection Standards. 6/15/2007 12/28/11 [Insert FR page number where document begins] PART 11. Visibility Protection Standards Title/ subject State citation EPA APPROVED OKLAHOMA REGULATIONS * Explanation App. 195 Interstate transport for the 1997 ozone and PM2.5 NAAQS (Noninterference with measures required to prevent * Name of SIP provision Statewide * Applicable geographic or nonattainment area 5/1/2007 * State submittal/ effective date 11/26/2010, 75 FR 72701 12/28/11 [Insert citation of publication]. * EPA approval date Noninterference with measures required to prevent significant deterioration of air quality in any other State * Explanation EPA APPROVED NON-REGULATORY PROVISIONS AND QUASI-REGULATORY MEASURES IN THE OKLAHOMA SIP (e) * * * App. 196 12/28/11 [Insert citation of publication]. Core requirements of 40 CFR 51.308 2/17/2010 Regional haze SIP: Statewide approved 11/26/2010. Noninterference with measures required to protect visibility in any other State partially approved 12/28/11. deterioration of air quality or to protect visibility in any other State). App. 197 (b) Coordinating regional haze and reasonably attributable visibility impairment. (a) Determination of baseline and natural visibility conditions. App. 198 (e) BART determinations except for the following SO2 BART determinations: Units 4 and 5 of the Oklahoma Gas and Electric (OG&E) (d) Coordination with States and Federal Land Managers. c) Monitoring strategy and other implementation requirements. App. 199 Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; and Units 3 and 4 of the American Electric Power/Public Service Company of Oklahoma (AEP/PSO) Northeastern plant. App. 200 App. 201 # 3. Section 52.1923 is added to read as follows: § 52.1923 Best Available Retrofit Requirements (BART) for SO2 and Interstate pollutant transport provisions; What are the FIP requirements for Units 4 and 5 of the Oklahoma Gas and Electric Muskogee plant; Units 1 and 2 of the Oklahoma Gas and Electric Sooner plant; and Units 3 and 4 of the American Electric Power/Public Service Company of Oklahoma Northeastern plant affecting visibility? (a) Applicability. The provisions of this section shall apply to each owner or operator, or successive owners or operators, of the coal burning equipment designated as: Units 4 or 5 of the Oklahoma Gas and Electric Muskogee plant; Units 1 or 2 of the Oklahoma Gas and Electric Sooner plant; and Units 3 or 4 of the American Electric Power/Public Service Company of Oklahoma Northeastern plant. (b) Compliance Dates. Compliance with the requirements of this section is required within five years of the effective date of this rule unless otherwise indicated by compliance dates contained in specific provisions. (c) Definitions. All terms used in this part but not defined herein shall have the meaning given them in the CAA and in parts 51 and 60 of this title. For the purposes of this section: 24-hour period means the period of time between 12:01 a.m. and 12 midnight. Air pollution control equipment includes selective catalytic control units, baghouses, particulate or App. 202 gaseous scrubbers, and any other apparatus utilized to control emissions of regulated air contaminants that would be emitted to the atmosphere. Boiler-operating-day means any 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time at the steam generating unit. Daily average means the arithmetic average of the hourly values measured in a 24-hour period. Heat input means heat derived from combustion of fuel in a unit and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources. Heat input shall be calculated in accordance with 40 CFR part 75. Owner or Operator means any person who owns, leases, operates, controls, or supervises any of the coal burning equipment designated as: Unit 4 of the Oklahoma Gas and Electric Muskogee plant; or Unit 5 of the Oklahoma Gas and Electric Muskogee plant; or Unit 1 of the Oklahoma Gas and Electric Sooner plant; or Unit 2 of the Oklahoma Gas and Electric Sooner plant; or Unit 3 of the American Electric Power/Public Service Company of Oklahoma Northeastern plant; or App. 203 Unit 4 of the American Electric Power/Public Service Company of Oklahoma Northeastern plant. Regional Administrator means the Regional Administrator of EPA Region 6 or his/her authorized representative. Unit means one of the coal fired boilers covered under Paragraph (a), above. (d) Emissions Limitations. SO2 emission limit. The individual sulfur dioxide emission limit for a unit shall be 0.06 pounds per million British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-operating-day period. For each unit, SO2 emissions for each calendar day shall be determined by summing the hourly emissions measured in pounds of SO2. For each unit, heat input for each boiler-operating-day shall be determined by adding together all hourly heat inputs, in millions of BTU. Each boiler-operating-day the thirty-day rolling average for a unit shall be determined by adding together the pounds of SO2 from that day and the preceding 29 boiler-operating-days and dividing the total pounds of SO2 by the sum of the heat input during the same 30 boiler-operating-day period. The result shall be the 30 boiler-operating-day rolling average in terms of lb/MMBtu emissions of SO2. If a valid SO2 pounds per hour or heat input is not available for any hour for a unit, that heat input and SO2 pounds per hour shall not be used in the calculation of the 30 boiler-operating-day rolling average for SO2. App. 204 (e) Testing and monitoring. (1) No later than the compliance date of this regulation, the owner or operator shall install, calibrate, maintain and operate Continuous Emissions Monitoring Systems (CEMS) for SO2 on Units 4 and 5 of the Oklahoma Gas and Electric Muskogee plant; Units 1 and 2 of the Oklahoma Gas and Electric Sooner plant; and Units 3 and 4 of the American Electric Power/Public Service Company of Oklahoma Northeastern plant in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), and Appendix B of Part 60. The owner or operator shall comply with the quality assurance procedures for CEMS found in 40 CFR part 75. Compliance with the emission limits for SO2 shall be determined by using data from a CEMS. (2) Continuous emissions monitoring shall apply during all periods of operation of the coal burning equipment, including periods of startup, shutdown, and malfunction, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments. Continuous monitoring systems for measuring SO2 and diluent gas shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period. Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant in an hour) if data are unavailable as a result of performance of calibration, quality assurance, preventive maintenance activities, or backups of data from data acquisition and handling system, and App. 205 recertification events. When valid SO2 pounds per hour, or SO2 pounds per million Btu emission data are not obtained because of continuous monitoring system breakdowns, repairs, calibration checks, or zero and span adjustments, emission data must be obtained by using other monitoring systems approved by the EPA to provide emission data for a minimum of 18 hours in each 24 hour period and at least 22 out of 30 successive boiler operating days. (f) Reporting and Recordkeeping Requirements. Unless otherwise stated all requests, reports, submittals, notifications, and other communications to the Regional Administrator required by this section shall be submitted, unless instructed otherwise, to the Director, Multimedia Planning and Permitting Division, U.S. Environmental Protection Agency, Region 6, to the attention of Mail Code: 6PD, at 1445 Ross Avenue, Suite 1200, Dallas, Texas 75202––2733. For each unit subject to the emissions limitation in this section and upon completion of the installation of CEMS as required in this section, the owner or operator shall comply with the following requirements: (1) For each emissions limit in this section, comply with the notification, reporting, and recordkeeping requirements for CEMS compliance monitoring in 40 CFR 60.7(c) and (d). (2) For each day, provide the total SO2 emitted that day by each emission unit. For any hours on any unit where data for hourly pounds or heat input is missing, identify the unit number and monitoring device that did not produce valid data that caused the missing hour. App. 206 (g) Equipment Operations. At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the unit including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, review of operating and maintenance procedures, and inspection of the unit. (h) Enforcement. (1) Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant as to whether the unit would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard or applicable emission limit in the plan. (2) Emissions in excess of the level of the applicable emission limit or requirement that occur due to a malfunction shall constitute a violation of the applicable emission limit. # 4. Section 52.1928 is added to read as follows: § 52.1928 Visibility protection. (a) The following portions of the Oklahoma Regional Haze (RH) State Implementation Plan submitted on February 19, 2010 are disapproved: App. 207 (1) The SO2 BART determinations for Units 4 and 5 of the Oklahoma Gas and Electric (OG&E) Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; and Units 3 and 4 of the American Electric Power/Public Service Company of Oklahoma (AEP/PSO) Northeastern plant; (2) The long-term strategy for regional haze; (3) ““Greater Reasonable Progress Alternative Determination”” (section VI.E), and (4) Separate executed agreements between ODEQ and OG&E, and ODEQ and AEP/PSO entitled ““OG&E Regional Haze Agreement, Case No. 10––024, and ““PSO Regional Haze Agreement, Case No. 10––025,”” housed within Appendix 6––5 of the RH SIP. (b) The portion of the State Implementation Plan pertaining to adequate provisions to prohibit emissions from interfering with measures required in another state to protect visibility, submitted on May 10, 2007 and supplemented on December 10, 2007 is disapproved. (c) The SO2 BART requirements for Units 4 and 5 of the Oklahoma Gas and Electric (OG&E) Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; and Units 3 and 4 of the American Electric Power/Public Service Company of Oklahoma (AEP/PSO) Northeastern plant, the deficiencies in the long-term strategy for regional haze, and the requirement for a plan to contain adequate provisions to prohibit emissions from interfering with measures required in another state to protect visibility are satisfied by § 52.1923. App. 208 Doc. 2011?32572 Filed 12?27?11; 8:45 am] BILLING CODE App. 209 APPENDIX C UNITED STATES COURT OF APPEALS FOR THE TENTH CIRCUIT [Filed October 31, 2013] No. 12-9526 _______________________________________ STATE OF OKLAHOMA, et al., ) Petitioners, ) ) v. ) ) UNITED STATES ENVIRONMENTAL ) PROTECTION AGENCY, ) Respondent. ) --------------------------------------------------------- ) SIERRA CLUB, ) Intervenor - Respondent, ) ) and ) ) PACIFICORP, et al., ) Amici Curiae. ) _______________________________________) No. 12-9527 _______________________________________ OKLAHOMA GAS & ELECTRIC ) COMPANY, ) Petitioner, ) ) v. ) App. 210 ) ) ) ) ) ) ) ) and ) ) PACIFICORP, et al., ) Amici Curiae. ) _______________________________________) UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, Respondent. --------------------------------------------------------SIERRA CLUB, Intervenor - Respondent, ORDER Before BRISCOE, Chief LUCERO, Circuit Judges. Judge, KELLY, and Petitioners’’ petition for panel rehearing in 12-9526 is denied. Petitioner’’s petition for panel rehearing in 12-9527 is also denied. Judge Kelly would grant panel rehearing in both cases, consistent with his concurring and dissenting opinion. The petitions for rehearing en banc were transmitted to all of the judges of the court who are in regular active service. As no member of the panel and no judge in regular active service on the court requested that the court be polled, those petitions are also denied. Entered for the Court /s/ Elisabeth A. Shumaker ELISABETH A. SHUMAKER, Clerk App. 211 APPENDIX D 42 U.S.C.A. § 7491 § 7491. Visibility protection for Federal class I areas Currentness (a) Impairment of visibility; list of areas; study and report (1) Congress hereby declares as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory class I Federal areas which impairment results from manmade air pollution. (2) Not later than six months after August 7, 1977, the Secretary of the Interior in consultation with other Federal land managers shall review all mandatory class I Federal areas and identify those where visibility is an important value of the area. From time to time the Secretary of the Interior may revise such identifications. Not later than one year after August 7, 1977, the Administrator shall, after consultation with the Secretary of the Interior, promulgate a list of mandatory class I Federal areas in which he determines visibility is an important value. (3) Not later than eighteen months after August 7, 1977, the Administrator shall complete a study and report to Congress on available methods for implementing the national goal set forth in App. 212 paragraph (1). Such recommendations for-- report shall include (A) methods for identifying, characterizing, determining, quantifying, and measuring visibility impairment in Federal areas referred to in paragraph (1), and (B) modeling techniques (or other methods) for determining the extent to which manmade air pollution may reasonably be anticipated to cause or contribute to such impairment, and (C) methods for preventing and remedying such manmade air pollution and resulting visibility impairment. Such report shall also identify the classes or categories of sources and the types of air pollutants which, alone or in conjunction with other sources or pollutants, may reasonably be anticipated to cause or contribute significantly to impairment of visibility. (4) Not later than twenty-four months after August 7, 1977, and after notice and public hearing, the Administrator shall promulgate regulations to assure (A) reasonable progress toward meeting the national goal specified in paragraph (1), and (B) compliance with the requirements of this section. (b) Regulations Regulations under subsection (a)(4) of this section shall-(1) provide guidelines to the States, taking into account the recommendations under subsection (a)(3) of this section on appropriate techniques and App. 213 methods for implementing this section (as provided in subparagraphs (A) through (C) of such subsection (a)(3)), and (2) require each applicable implementation plan for a State in which any area listed by the Administrator under subsection (a)(2) of this section is located (or for a State the emissions from which may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area) to contain such emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward meeting the national goal specified in subsection (a) of this section, including-(A) except as otherwise provided pursuant to subsection (c) of this section, a requirement that each major stationary source which is in existence on August 7, 1977, but which has not been in operation for more than fifteen years as of such date, and which, as determined by the State (or the Administrator in the case of a plan promulgated under section 7410(c) of this title) emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area, shall procure, install, and operate, as expeditiously as practicable (and maintain thereafter) the best available retrofit technology, as determined by the State (or the Administrator in the case of a plan promulgated under section 7410(c) of this title) for controlling emissions from such source for the purpose of eliminating or reducing any such impairment, and App. 214 (B) a long-term (ten to fifteen years) strategy for making reasonable progress toward meeting the national goal specified in subsection (a) of this section. In the case of a fossil-fuel fired generating powerplant having a total generating capacity in excess of 750 megawatts, the emission limitations required under this paragraph shall be determined pursuant to guidelines, promulgated by the Administrator under paragraph (1). (c) Exemptions (1) The Administrator may, by rule, after notice and opportunity for public hearing, exempt any major stationary source from the requirement of subsection (b)(2)(A) of this section, upon his determination that such source does not or will not, by itself or in combination with other sources, emit any air pollutant which may reasonably be anticipated to cause or contribute to a significant impairment of visibility in any mandatory class I Federal area. (2) Paragraph (1) of this subsection shall not be applicable to any fossil-fuel fired powerplant with total design capacity of 750 megawatts or more, unless the owner or operator of any such plant demonstrates to the satisfaction of the Administrator that such powerplant is located at such distance from all areas listed by the Administrator under subsection (a)(2) of this section that such powerplant does not or will not, by itself or in combination with other sources, emit any air App. 215 pollutant which may reasonably be anticipated to cause or contribute to significant impairment of visibility in any such area. (3) An exemption under this subsection shall be effective only upon concurrence by the appropriate Federal land manager or managers with the Administrator’’s determination under this subsection. (d) Consultations with appropriate Federal land managers Before holding the public hearing on the proposed revision of an applicable implementation plan to meet the requirements of this section, the State (or the Administrator, in the case of a plan promulgated under section 7410(c) of this title) shall consult in person with the appropriate Federal land manager or managers and shall include a summary of the conclusions and recommendations of the Federal land managers in the notice to the public. (e) Buffer zones In promulgating regulations under this section, the Administrator shall not require the use of any automatic or uniform buffer zone or zones. (f) Nondiscretionary duty For purposes of section 7604(a)(2) of this title, the meeting of the national goal specified in subsection (a)(1) of this section by any specific date or dates shall not be considered a ““nondiscretionary duty”” of the Administrator. App. 216 (g) Definitions For the purpose of this section-(1) in determining reasonable progress there shall be taken into consideration the costs of compliance, the time necessary for compliance, and the energy and nonair quality environmental impacts of compliance, and the remaining useful life of any existing source subject to such requirements; (2) in determining best available retrofit technology the State (or the Administrator in determining emission limitations which reflect such technology) shall take into consideration the costs of compliance, the energy and nonair quality environmental impacts of compliance, any existing pollution control technology in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology; (3) the term ““manmade air pollution”” means air pollution which results directly or indirectly from human activities; (4) the term ““as expeditiously as practicable”” means as expeditiously as practicable but in no event later than five years after the date of approval of a plan revision under this section (or the date of promulgation of such a plan revision in the case of action by the Administrator under section 7410(c) of this title for purposes of this section); App. 217 (5) the term ““mandatory class I Federal areas”” means Federal areas which may not be designated as other than class I under this part; (6) the terms ““visibility impairment”” and ““impairment of visibility”” shall include reduction in visual range and atmospheric discoloration; and (7) the term ““major stationary source”” means the following types of stationary sources with the potential to emit 250 tons or more of any pollutant: fossil-fuel fired steam electric plants of more than 250 million British thermal units per hour heat input, coal cleaning plants (thermal dryers), kraft pulp mills, Portland Cement plants, primary zinc smelters, iron and steel mill plants, primary aluminum ore reduction plants, primary copper smelters, municipal incinerators capable of charging more than 250 tons of refuse per day, hydrofluoric, sulfuric, and nitric acid plants, petroleum refineries, lime plants, phosphate rock processing plants, coke oven batteries, sulfur recovery plants, carbon black plants (furnace process), primary lead smelters, fuel conversion plants, sintering plants, secondary metal production facilities, chemical process plants, fossil-fuel boilers of more than 250 million British thermal units per hour heat input, petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels, taconite ore processing facilities, glass fiber processing plants, charcoal production facilities. App. 218 40 C.F.R. § 51.308 § 51.308 Regional haze program requirements. Effective: August 6, 2012 Currentness (a) What is the purpose of this section? This section establishes requirements for implementation plans, plan revisions, and periodic progress reviews to address regional haze. (b) When are the first implementation plans due under the regional haze program? Except as provided in § 51.309(c), each State identified in § 51.300(b)(3) must submit, for the entire State, an implementation plan for regional haze meeting the requirements of paragraphs (d) and (e) of this section no later than December 17, 2007. (c) [Reserved] (d) What are the core requirements for the implementation plan for regional haze? The State must address regional haze in each mandatory Class I Federal area located within the State and in each mandatory Class I Federal area located outside the State which may be affected by emissions from within the State. To meet the core requirements for regional haze for these areas, the State must submit an implementation plan containing the following plan elements and supporting documentation for all required analyses: (1) Reasonable progress goals. For each mandatory Class I Federal area located within the State, the State must establish goals (expressed in App. 219 deciviews) that provide for reasonable progress towards achieving natural visibility conditions. The reasonable progress goals must provide for an improvement in visibility for the most impaired days over the period of the implementation plan and ensure no degradation in visibility for the least impaired days over the same period. (i) In establishing a reasonable progress goal for any mandatory Class I Federal area within the State, the State must: (A) Consider the costs of compliance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, and the remaining useful life of any potentially affected sources, and include a demonstration showing how these factors were taken into consideration in selecting the goal. (B) Analyze and determine the rate of progress needed to attain natural visibility conditions by the year 2064. To calculate this rate of progress, the State must compare baseline visibility conditions to natural visibility conditions in the mandatory Federal Class I area and determine the uniform rate of visibility improvement (measured in deciviews) that would need to be maintained during each implementation period in order to attain natural visibility conditions by 2064. In establishing the reasonable progress goal, the State must consider the uniform rate of improvement in visibility and the emission reduction measures needed to achieve it for the period covered by the implementation plan. App. 220 (ii) For the period of the implementation plan, if the State establishes a reasonable progress goal that provides for a slower rate of improvement in visibility than the rate that would be needed to attain natural conditions by 2064, the State must demonstrate, based on the factors in paragraph (d)(1)(i)(A) of this section, that the rate of progress for the implementation plan to attain natural conditions by 2064 is not reasonable; and that the progress goal adopted by the State is reasonable. The State must provide to the public for review as part of its implementation plan an assessment of the number of years it would take to attain natural conditions if visibility improvement continues at the rate of progress selected by the State as reasonable. (iii) In determining whether the State’’s goal for visibility improvement provides for reasonable progress towards natural visibility conditions, the Administrator will evaluate the demonstrations developed by the State pursuant to paragraphs (d)(1)(i) and (d)(1)(ii) of this section. (iv) In developing each reasonable progress goal, the State must consult with those States which may reasonably be anticipated to cause or contribute to visibility impairment in the mandatory Class I Federal area. In any situation in which the State cannot agree with another such State or group of States that a goal provides for reasonable progress, the State must describe in its submittal the actions taken to resolve the disagreement. In reviewing the State’’s implementation plan submittal, the Administrator will take this information into account in determining whether the State’’s goal for App. 221 visibility improvement provides for reasonable progress towards natural visibility conditions. (v) The reasonable progress goals established by the State are not directly enforceable but will be considered by the Administrator in evaluating the adequacy of the measures in the implementation plan to achieve the progress goal adopted by the State. (vi) The State may not adopt a reasonable progress goal that represents less visibility improvement than is expected to result from implementation of other requirements of the CAA during the applicable planning period. (2) Calculations of baseline and natural visibility conditions. For each mandatory Class I Federal area located within the State, the State must determine the following visibility conditions (expressed in deciviews): (i) Baseline visibility conditions for the most impaired and least impaired days. The period for establishing baseline visibility conditions is 2000 to 2004. Baseline visibility conditions must be calculated, using available monitoring data, by establishing the average degree of visibility impairment for the most and least impaired days for each calendar year from 2000 to 2004. The baseline visibility conditions are the average of these annual values. For mandatory Class I Federal areas without onsite monitoring data for 2000-2004, the State must establish baseline values using the most representative available monitoring data for App. 222 2000-2004, in consultation with the Administrator or his or her designee; (ii) For an implementation plan that is submitted by 2003, the period for establishing baseline visibility conditions for the period of the first long-term strategy is the most recent 5——year period for which visibility monitoring data are available for the mandatory Class I Federal areas addressed by the plan. For mandatory Class I Federal areas without onsite monitoring data, the State must establish baseline values using the most representative available monitoring data, in consultation with the Administrator or his or her designee; (iii) Natural visibility conditions for the most impaired and least impaired days. Natural visibility conditions must be calculated by estimating the degree of visibility impairment existing under natural conditions for the most impaired and least impaired days, based on available monitoring information and appropriate data analysis techniques; and (iv)(A) For the first implementation plan addressing the requirements of paragraphs (d) and (e) of this section, the number of deciviews by which baseline conditions exceed natural visibility conditions for the most impaired and least impaired days; or (B) For all future implementation plan revisions, the number of deciviews by which current conditions, as calculated under paragraph (f)(1) of this section, exceed natural App. 223 visibility conditions for the most impaired and least impaired days. (3) Long-term strategy for regional haze. Each State listed in § 51.300(b)(3) must submit a long-term strategy that addresses regional haze visibility impairment for each mandatory Class I Federal area within the State and for each mandatory Class I Federal area located outside the State which may be affected by emissions from the State. The long-term strategy must include enforceable emissions limitations, compliance schedules, and other measures as necessary to achieve the reasonable progress goals established by States having mandatory Class I Federal areas. In establishing its long-term strategy for regional haze, the State must meet the following requirements: (i) Where the State has emissions that are reasonably anticipated to contribute to visibility impairment in any mandatory Class I Federal area located in another State or States, the State must consult with the other State(s) in order to develop coordinated emission management strategies. The State must consult with any other State having emissions that are reasonably anticipated to contribute to visibility impairment in any mandatory Class I Federal area within the State. (ii) Where other States cause or contribute to impairment in a mandatory Class I Federal area, the State must demonstrate that it has included in its implementation plan all measures necessary to obtain its share of the emission reductions needed to meet the progress goal for the area. If the State App. 224 has participated in a regional planning process, the State must ensure it has included all measures needed to achieve its apportionment of emission reduction obligations agreed upon through that process. (iii) The State must document the technical basis, including modeling, monitoring and emissions information, on which the State is relying to determine its apportionment of emission reduction obligations necessary for achieving reasonable progress in each mandatory Class I Federal area it affects. The State may meet this requirement by relying on technical analyses developed by the regional planning organization and approved by all State participants. The State must identify the baseline emissions inventory on which its strategies are based. The baseline emissions inventory year is presumed to be the most recent year of the consolidate periodic emissions inventory. (iv) The State must identify all anthropogenic sources of visibility impairment considered by the State in developing its long-term strategy. The State should consider major and minor stationary sources, mobile sources, and area sources. (v) The State must consider, at a minimum, the following factors in developing its long-term strategy: (A) Emission reductions due to ongoing air pollution control programs, including measures to address reasonably attributable visibility impairment; App. 225 (B) Measures to mitigate the impacts of construction activities; (C) Emissions limitations and schedules for compliance to achieve the reasonable progress goal; (D) Source schedules; retirement and replacement (E) Smoke management techniques for agricultural and forestry management purposes including plans as currently exist within the State for these purposes; (F) Enforceability of emissions limitations and control measures; and (G) The anticipated net effect on visibility due to projected changes in point, area, and mobile source emissions over the period addressed by the long-term strategy. (4) Monitoring strategy and other implementation plan requirements. The State must submit with the implementation plan a monitoring strategy for measuring, characterizing, and reporting of regional haze visibility impairment that is representative of all mandatory Class I Federal areas within the State. This monitoring strategy must be coordinated with the monitoring strategy required in § 51.305 for reasonably attributable visibility impairment. Compliance with this requirement may be met through participation in the Interagency Monitoring of Protected Visual Environments network. The implementation plan must also provide for the following: App. 226 (i) The establishment of any additional monitoring sites or equipment needed to assess whether reasonable progress goals to address regional haze for all mandatory Class I Federal areas within the State are being achieved. (ii) Procedures by which monitoring data and other information are used in determining the contribution of emissions from within the State to regional haze visibility impairment at mandatory Class I Federal areas both within and outside the State. (iii) For a State with no mandatory Class I Federal areas, procedures by which monitoring data and other information are used in determining the contribution of emissions from within the State to regional haze visibility impairment at mandatory Class I Federal areas in other States. (iv) The implementation plan must provide for the reporting of all visibility monitoring data to the Administrator at least annually for each mandatory Class I Federal area in the State. To the extent possible, the State should report visibility monitoring data electronically. (v) A statewide inventory of emissions of pollutants that are reasonably anticipated to cause or contribute to visibility impairment in any mandatory Class I Federal area. The inventory must include emissions for a baseline year, emissions for the most recent year for which data are available, and estimates of future projected emissions. The State must also include a commitment to update the inventory periodically. App. 227 (vi) Other elements, including reporting, recordkeeping, and other measures, necessary to assess and report on visibility. (e) Best Available Retrofit Technology (BART) requirements for regional haze visibility impairment. The State must submit an implementation plan containing emission limitations representing BART and schedules for compliance with BART for each BART——eligible source that may reasonably be anticipated to cause or contribute to any impairment of visibility in any mandatory Class I Federal area, unless the State demonstrates that an emissions trading program or other alternative will achieve greater reasonable progress toward natural visibility conditions. (1) To address the requirements for BART, the State must submit an implementation plan containing the following plan elements and include documentation for all required analyses: (i) A list of all BART——eligible sources within the State. (ii) A determination of BART for each BART——eligible source in the State that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any mandatory Class I Federal area. All such sources are subject to BART. (A) The determination of BART must be based on an analysis of the best system of continuous emission control technology available and associated emission reductions achievable for each BART——eligible source that is subject to App. 228 BART within the State. In this analysis, the State must take into consideration the technology available, the costs of compliance, the energy and nonair quality environmental impacts of compliance, any pollution control equipment in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. (B) The determination of BART for fossil-fuel fired power plants having a total generating capacity greater than 750 megawatts must be made pursuant to the guidelines in appendix Y of this part (Guidelines for BART Determinations Under the Regional Haze Rule). (C) Exception. A State is not required to make a determination of BART for SO2 or for NOX if a BART——eligible source has the potential to emit less than 40 tons per year of such pollutant(s), or for PM10 if a BART——eligible source has the potential to emit less than 15 tons per year of such pollutant. (iii) If the State determines in establishing BART that technological or economic limitations on the applicability of measurement methodology to a particular source would make the imposition of an emission standard infeasible, it may instead prescribe a design, equipment, work practice, or other operational standard, or combination thereof, to require the application of BART. Such standard, to the degree possible, is to set forth the emission reduction to be achieved by implementation of such App. 229 design, equipment, work practice or operation, and must provide for compliance by means which achieve equivalent results. (iv) A requirement that each source subject to BART be required to install and operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the implementation plan revision. (v) A requirement that each source subject to BART maintain the control equipment required by this subpart and establish procedures to ensure such equipment is properly operated and maintained. (2) A State may opt to implement or require participation in an emissions trading program or other alternative measure rather than to require sources subject to BART to install, operate, and maintain BART. Such an emissions trading program or other alternative measure must achieve greater reasonable progress than would be achieved through the installation and operation of BART. For all such emission trading programs or other alternative measures, the State must submit an implementation plan containing the following plan elements and include documentation for all required analyses: (i) A demonstration that the emissions trading program or other alternative measure will achieve greater reasonable progress than would have resulted from the installation and operation of BART at all sources subject to BART in the State App. 230 and covered by the alternative program. This demonstration must be based on the following: (A) A list of all BART——eligible sources within the State. (B) A list of all BART——eligible sources and all BART source categories covered by the alternative program. The State is not required to include every BART source category or every BART——eligible source within a BART source category in an alternative program, but each BART——eligible source in the State must be subject to the requirements of the alternative program, have a federally enforceable emission limitation determined by the State and approved by EPA as meeting BART in accordance with section 302(c) or paragraph (e)(1) of this section, or otherwise addressed under paragraphs (e)(1) or (e)(4)of this section. (C) An analysis of the best system of continuous emission control technology available and associated emission reductions achievable for each source within the State subject to BART and covered by the alternative program. This analysis must be conducted by making a determination of BART for each source subject to BART and covered by the alternative program as provided for in paragraph (e)(1) of this section, unless the emissions trading program or other alternative measure has been designed to meet a requirement other than BART (such as the core requirement to have a long-term strategy to achieve the reasonable progress goals established by States). In this case, the State App. 231 may determine the best system of continuous emission control technology and associated emission reductions for similar types of sources within a source category based on both source-specific and category-wide information, as appropriate. (D) An analysis of the projected emissions reductions achievable through the trading program or other alternative measure. (E) A determination under paragraph (e)(3) of this section or otherwise based on the clear weight of evidence that the trading program or other alternative measure achieves greater reasonable progress than would be achieved through the installation and operation of BART at the covered sources. (ii) [Reserved] (iii) A requirement that all necessary emission reductions take place during the period of the first long-term strategy for regional haze. To meet this requirement, the State must provide a detailed description of the emissions trading program or other alternative measure, including schedules for implementation, the emission reductions required by the program, all necessary administrative and technical procedures for implementing the program, rules for accounting and monitoring emissions, and procedures for enforcement. (iv) A demonstration that the emission reductions resulting from the emissions trading program or other alternative measure will be surplus to those reductions resulting from measures adopted to meet App. 232 requirements of the CAA as of the baseline date of the SIP. (v) At the State’’s option, a provision that the emissions trading program or other alternative measure may include a geographic enhancement to the program to address the requirement under § 51.302(c) related to BART for reasonably attributable impairment from the pollutants covered under the emissions trading program or other alternative measure. (vi) For plans that include an emissions trading program that establishes a cap on total annual emissions of SO2 or NOX from sources subject to the program, requires the owners and operators of sources to hold allowances or authorizations to emit equal to emissions, and allows the owners and operators of sources and other entities to purchase, sell, and transfer allowances, the following elements are required concerning the emissions covered by the cap: (A) Applicability provisions defining the sources subject to the program. The State must demonstrate that the applicability provisions (including the size criteria for including sources in the program) are designed to prevent any significant potential shifting within the State of production and emissions from sources in the program to sources outside the program. In the case of a program covering sources in multiple States, the States must demonstrate that the applicability provisions in each State cover essentially the same size facilities and, if source categories are specified, cover the same source App. 233 categories and prevent any significant, potential shifting within such States of production and emissions to sources outside the program. (B) Allowance provisions ensuring that the total value of allowances (in tons) issued each year under the program will not exceed the emissions cap (in tons) on total annual emissions from the sources in the program. (C) Monitoring provisions providing for consistent and accurate measurements of emissions from sources in the program to ensure that each allowance actually represents the same specified tonnage of emissions and that emissions are measured with similar accuracy at all sources in the program. The monitoring provisions must require that boilers, combustion turbines, and cement kilns in the program allowed to sell or transfer allowances must comply with the requirements of part 75 of this chapter. The monitoring provisions must require that other sources in the program allowed to sell or transfer allowances must provide emissions information with the same precision, reliability, accessibility, and timeliness as information provided under part 75 of this chapter. (D) Recordkeeping provisions that ensure the enforceability of the emissions monitoring provisions and other program requirements. The recordkeeping provisions must require that boilers, combustion turbines, and cement kilns in the program allowed to sell or transfer allowances must comply with the recordkeeping provisions of part 75 of this chapter. The App. 234 recordkeeping provisions must require that other sources in the program allowed to sell or transfer allowances must comply with recordkeeping requirements that, as compared with the recordkeeping provisions under part 75 of this chapter, are of comparable stringency and require recording of comparable types of information and retention of the records for comparable periods of time. (E) Reporting provisions requiring timely reporting of monitoring data with sufficient frequency to ensure the enforceability of the emissions monitoring provisions and other program requirements and the ability to audit the program. The reporting provisions must require that boilers, combustion turbines, and cement kilns in the program allowed to sell or transfer allowances must comply with the reporting provisions of part 75 of this chapter, except that, if the Administrator is not the tracking system administrator for the program, emissions may be reported to the tracking system administrator, rather than to the Administrator. The reporting provisions must require that other sources in the program allowed to sell or transfer allowances must comply with reporting requirements that, as compared with the reporting provisions under part 75 of this chapter, are of comparable stringency and require reporting of comparable types of information and require comparable timeliness and frequency of reporting. App. 235 (F) Tracking system provisions which provide for a tracking system that is publicly available in a secure, centralized database to track in a consistent manner all allowances and emissions in the program. (G) Authorized account representative provisions ensuring that the owners and operators of a source designate one individual who is authorized to represent the owners and operators in all matters pertaining to the trading program. (H) Allowance transfer provisions providing procedures that allow timely transfer and recording of allowances, minimize administrative barriers to the operation of the allowance market, and ensure that such procedures apply uniformly to all sources and other potential participants in the allowance market. (I) Compliance provisions prohibiting a source from emitting a total tonnage of a pollutant that exceeds the tonnage value of its allowance holdings, including the methods and procedures for determining whether emissions exceed allowance holdings. Such method and procedures shall apply consistently from source to source. (J) Penalty provisions providing for mandatory allowance deductions for excess emissions that apply consistently from source to source. The tonnage value of the allowances App. 236 deducted shall equal at least three times the tonnage of the excess emissions. (K) For a trading program that allows banking of allowances, provisions clarifying any restrictions on the use of these banked allowances. (L) Program assessment provisions providing for periodic program evaluation to assess whether the program is accomplishing its goals and whether modifications to the program are needed to enhance performance of the program. (3) A State which opts under 40 CFR 51.308(e)(2) to implement an emissions trading program or other alternative measure rather than to require sources subject to BART to install, operate, and maintain BART may satisfy the final step of the demonstration required by that section as follows: If the distribution of emissions is not substantially different than under BART, and the alternative measure results in greater emission reductions, then the alternative measure may be deemed to achieve greater reasonable progress. If the distribution of emissions is significantly different, the State must conduct dispersion modeling to determine differences in visibility between BART and the trading program for each impacted Class I area, for the worst and best 20 percent of days. The modeling would demonstrate ““greater reasonable progress”” if both of the following two criteria are met: (i) and Visibility does not decline in any Class I area, App. 237 (ii) There is an overall improvement in visibility, determined by comparing the average differences between BART and the alternative over all affected Class I areas. (4) A State subject to a trading program established in accordance with § 52.38 or § 52.39 under a Transport Rule Federal Implementation Plan need not require BART——eligible fossil fuel-fired steam electric plants in the State to install, operate, and maintain BART for the pollutant covered by such trading program in the State. A State that chooses to meet the emission reduction requirements of the Transport Rule by submitting a SIP revision that establishes a trading program and is approved as meeting the requirements of § 52.38 or § 52.39 also need not require BART——eligible fossil fuel-fired steam electric plants in the State to install, operate, and maintain BART for the pollutant covered by such trading program in the State. A State may adopt provisions, consistent with the requirements applicable to the State for a trading program established in accordance with § 52.38 or § 52.39 under the Transport Rule Federal Implementation Plan or established under a SIP revision that is approved as meeting the requirements of § 52.38 or § 52.39, for a geographic enhancement to the program to address the requirement under § 51.302(c) related to BART for reasonably attributable impairment from the pollutant covered by such trading program in that State. (5) After a State has met the requirements for BART or implemented emissions trading program App. 238 or other alternative measure that achieves more reasonable progress than the installation and operation of BART, BART——eligible sources will be subject to the requirements of paragraph (d) of this section in the same manner as other sources. (6) Any BART——eligible facility subject to the requirement under paragraph (e) of this section to install, operate, and maintain BART may apply to the Administrator for an exemption from that requirement. An application for an exemption will be subject to the requirements of § 51.303(a)(2)-(h). (f) Requirements for comprehensive periodic revisions of implementation plans for regional haze. Each State identified in § 51.300(b)(3) must revise and submit its regional haze implementation plan revision to EPA by July 31, 2018 and every ten years thereafter. In each plan revision, the State must evaluate and reassess all of the elements required in paragraph (d) of this section, taking into account improvements in monitoring data collection and analysis techniques, control technologies, and other relevant factors. In evaluating and reassessing these elements, the State must address the following: (1) Current visibility conditions for the most impaired and least impaired days, and actual progress made towards natural conditions during the previous implementation period. The period for calculating current visibility conditions is the most recent five year period preceding the required date of the implementation plan submittal for which data are available. Current visibility conditions must be calculated based on the annual average level of visibility impairment for the most and least App. 239 impaired days for each of these five years. Current visibility conditions are the average of these annual values. (2) The effectiveness of the long-term strategy for achieving reasonable progress goals over the prior implementation period(s); and (3) Affirmation of, or revision to, the reasonable progress goal in accordance with the procedures set forth in paragraph (d)(1) of this section. If the State established a reasonable progress goal for the prior period which provided a slower rate of progress than that needed to attain natural conditions by the year 2064, the State must evaluate and determine the reasonableness, based on the factors in paragraph (d)(1)(i)(A) of this section, of additional measures that could be adopted to achieve the degree of visibility improvement projected by the analysis contained in the first implementation plan described in paragraph (d)(1)(i)(B) of this section. (g) Requirements for periodic reports describing progress towards the reasonable progress goals. Each State identified in § 51.300(b)(3) must submit a report to the Administrator every 5 years evaluating progress towards the reasonable progress goal for each mandatory Class I Federal area located within the State and in each mandatory Class I Federal area located outside the State which may be affected by emissions from within the State. The first progress report is due 5 years from submittal of the initial implementation plan addressing paragraphs (d) and (e) of this section. The progress reports must be in the form of implementation plan revisions that comply with the procedural requirements of § 51.102 and App. 240 § 51.103. Periodic progress reports must contain at a minimum the following elements: (1) A description of the status of implementation of all measures included in the implementation plan for achieving reasonable progress goals for mandatory Class I Federal areas both within and outside the State. (2) A summary of the emissions reductions achieved throughout the State through implementation of the measures described in paragraph (g)(1) of this section. (3) For each mandatory Class I Federal area within the State, the State must assess the following visibility conditions and changes, with values for most impaired and least impaired days expressed in terms of 5——year averages of these annual values. (i) The current visibility conditions for the most impaired and least impaired days; (ii) The difference between current visibility conditions for the most impaired and least impaired days and baseline visibility conditions; (iii) The change in visibility impairment for the most impaired and least impaired days over the past 5 years; (4) An analysis tracking the change over the past 5 years in emissions of pollutants contributing to visibility impairment from all sources and activities within the State. Emissions changes should be identified by type of source or activity. The analysis App. 241 must be based on the most recent updated emissions inventory, with estimates projected forward as necessary and appropriate, to account for emissions changes during the applicable 5——year period. (5) An assessment of any significant changes in anthropogenic emissions within or outside the State that have occurred over the past 5 years that have limited or impeded progress in reducing pollutant emissions and improving visibility. (6) An assessment of whether the current implementation plan elements and strategies are sufficient to enable the State, or other States with mandatory Federal Class I areas affected by emissions from the State, to meet all established reasonable progress goals. (7) A review of the State’’s visibility monitoring strategy and any modifications to the strategy as necessary. (h) Determination of the adequacy of existing implementation plan. At the same time the State is required to submit any 5——year progress report to EPA in accordance with paragraph (g) of this section, the State must also take one of the following actions based upon the information presented in the progress report: (1) If the State determines that the existing implementation plan requires no further substantive revision at this time in order to achieve established goals for visibility improvement and emissions reductions, the State must provide to the Administrator a negative declaration that further App. 242 revision of the existing implementation plan is not needed at this time. (2) If the State determines that the implementation plan is or may be inadequate to ensure reasonable progress due to emissions from sources in another State(s) which participated in a regional planning process, the State must provide notification to the Administrator and to the other State(s) which participated in the regional planning process with the States. The State must also collaborate with the other State(s) through the regional planning process for the purpose of developing additional strategies to address the plan’’s deficiencies. (3) Where the State determines that the implementation plan is or may be inadequate to ensure reasonable progress due to emissions from sources in another country, the State shall provide notification, along with available information, to the Administrator. (4) Where the State determines that the implementation plan is or may be inadequate to ensure reasonable progress due to emissions from sources within the State, the State shall revise its implementation plan to address the plan’’s deficiencies within one year. (i) What are the requirements for State and Federal Land Manager coordination? (1) By November 29, 1999, the State must identify in writing to the Federal Land Managers the title of the official to which the Federal Land Manager of any mandatory Class I Federal area can App. 243 submit any r ec om m end at ions on the implementation of this subpart including, but not limited to: (i) Identification of impairment of visibility in any mandatory Class I Federal area(s); and (ii) Identification of elements for inclusion in the visibility monitoring strategy required by § 51.305 and this section. App. 244 APPENDIX E Regional Haze Implementation Plan Revision State of Oklahoma Department of Environmental Quality February 2, 2010 * * * [p.81] * * * As outlined in the previous section and described in detail in Appendix 6-4, DEQ conducted a thorough case-by-case five-factor BART analysis for each of the BART-subject units. DEQ determined that Dry-Flue Gas Desulfurization with Spray Dryer Absorber (““Dry FGD with SDA””) is not cost-effective for S02 control for any of the six coal-fired steam electric units reviewed, i.e., OG&E Sooner Units 1 and 2, OG&E Muskogee Units 4 and 5, and PSO Northeastern Units 3 and 4. This determination is based on the capital cost of addon controls, the cost effectiveness both in dollars per ton and dollars per deciview of add-on controls, and the long term viability of coal with respect to other environmental programs, and national commitments. In addition to information provided prior to the public hearing, DEQ considered public comments, and additional information provided by the affected facilities in response to questions raised by the commentors and DEQ staff. Revised cost estimates App. 245 were provided by the affected facilities that are based on vendor quotes and go well beyond the default methodology recommended by EPA guidance. The cost estimates are credible, detailed, and specific for the individual facilities. The final estimate for Dry FGD with SDA for the six coal-fired units was on average 153% greater than the high end costs assumed by DEQ in the Draft SIP. These costs put the projects well above costs reported for other BART determinations, and above the levels DEQ considered reasonable for cost effectiveness both in terms of dollars per ton of pollutant removed and dollars per deciview (e.g., $10,000,000/dv) of improved visibilty. Tables VI-14 and VI-15 give data on these measures of cost-effectiveness. [p.82] * * * DEQ has determined that the cost for DFGD is too high and the benefit too low. These costs would further extend the life expectancy of coal as the primary fuel in the Sooner facility for at least 20 years and beyond. Consequently, DEQ has determined BART for the six coal-fired steam electric units to be the use (or continued use) of low sulfur coal. Additional explanation of DEQ’’s rationale and conclusions is included in the BART Determinations in Appendix 6-4. * * * App. 246 APPENDIX F UNITED STATES COURT OF APPEALS FOR THE TENTH CIRCUIT [Filed June 22, 2012] Nos. 12-9526 & 12-9527 (No. EPA-R06-OAR-2010-0190) _______________________________________ STATE OF OKLAHOMA; OKLAHOMA ) INDUSTRIAL ENERGY CONSUMERS, ) an unincorporated association; ) OKLAHOMA GAS & ELECTRIC ) COMPANY, ) Petitioners, ) ) v. ) ) UNITED STATES ENVIRONMENTAL ) PROTECTION AGENCY, ) Respondent. ) --------------------------------------------------------- ) SIERRA CLUB, ) Intervenor-Respondent. ) _______________________________________) ORDER Before KELLY and HOLMES, Circuit Judges. Petitioners, the State of Oklahoma, Oklahoma Industrial Energy Consumers, and the Oklahoma Gas & Electric Company, seek a stay pending review of that App. 247 portion of the Environmental Protection Agency’’s final rule requiring the reduction of sulfur dioxide emissions at four electric generating units. We conclude that the stay factors have been met in this case, and we therefore GRANT the motion for stay pending hearing by the merits panel. Entered for the Court /s/ Elisabeth A. Shumaker ELISABETH A. SHUMAKER, Clerk PnONIIfcUSIATESCUUHI UFAmALS" FOR DISTRICT OF COLUMBIA CIRCUIT ^DiSTRCTOFCOUiMBBSffi IN THE UNITED STATES COURT OF APPEA RECEIVED FOR THE DISTRICT OF COLUMBIA CI STATE OF WEST VIRGINIA; STATE OF ALABAMA; STATE OF ARIZONA; STATE OF KANSAS; COMMONWEALTH OF KENTUCKY; STATE OF LOUISIANA; ATTORNEY GENERAL BILL SCHUETTE, For the People of Michigan; STATE OF STATE OF STATE OF STATE OF STATE OF MONTANA; OHIO; OKLAHOMA; SOUTH CAROLINA; WISCONSIN; COMMONWEALTH OF KENTUCKY ENERGY AND ENVIRONMENT CABINET; and, STATE OF NORTH CAROLINA DEPARTMENT OF ENVIRONMENTAL QUALITY; Petitioners, UNITED STATES ENVIRONMENTAL PROTECTION AGENCY; and, REGINA A. MCCARTHY, Administrator, United States Environmental Protection Agency; Respondents. PETITION FOR REVIEW CaseNo. 16-1264 The States of West Virginia, Alabama, Arizona, Kansas, Louisiana, Montana, Ohio, Oklahoma, South Carolina, Wisconsin, and the Commonwealth of Kentucky, and Attorney General Bill Schuette for the People of Michigan, the Commonwealth of Kentucky Energy and Environment Cabinet, and the State of North Carolina Department of Environmental Quality hereby petition this Court, pursuant to Rule 15(a) of the Federal Rules of Appellate Procedure, Section 307(b)(1) of the Clean Air Act, 42 U.S.C. § 7607(b)(1), and 5 U.S.C. § 702, for review of the final rule of the U.S. Environmental Protection Agency published in the Federal Register at 81 Fed. Reg. 35,824 (June 3, 2016), titled "Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources." This Court has jurisdiction, and is a proper venue for this action, under 42 U.S.C. § 7607(b)(1). Petitioners will show that the final rule is in excess of the agency's statutory authority and otherwise is arbitrary, capricious, an abuse of discretion and not in accordance with law. Accordingly, Petitioners ask the Court to hold unlawful and set aside the rule, and to order other such relief as may be appropriate. See 42 U.S.C. § 7607(d). Dated: August 2, 2016 Respectfully submitted, Patrick Morrisey 0 Attorney General of West Virginia Elbert Lin Solicitor General Counsel ofRecord J. Zak Ritchie Assistant Attorney General State Capitol Building 1, Room 26-E Charleston, WV 25305 Tel: (304)558-2021 Fax: (304)558-0140 elbert.lin@wvago.gov Counselfor Petitioner State of West Virginia /M'Wur ^wyX Luther Strange Attorney General of Alabama Andrew Brasher Solicitor General Counsel ofRecord 501 Washington Avenue Montgomery, AL 36130 Tel: (334)353-2609 abrasher@ago.state.al.us Mark Brnovich ^ O Attorney General of Arizona John R. Lopez IV Solicitor General Counsel ofRecord 1275 West Washington St. Phoenix, AZ 85007 Tel: (602)542-8986 Fax (602) 542-8308 john.lopez@azag.gov Counselfor Petitioner State ofAlabama Counselfor Petitioner State ofArizona Derek Schmidt <~> u Attorney General of Kansas Jeffrey A. Chanay Chief Deputy Attorney General Counsel ofRecord Bryan C. Clark Assistant Solicitor General Andy Beshear O Attorney General of Kentucky Mitchel T. Denham Assistant Deputy Attorney General Joseph A. Newberg, II Assistant Attorney General Counsel ofRecord 700 Capital Avenue 120 S.W. 10th Avenue, 3rd Floor Topeka,KS 66612 Tel: (785)368-8435 Fax: (785)291-3767 Tel: (502)696-5611 jeff.chanay@ag.ks.gov joe.newberg@ky.gov Counselfor Petitioner State ofKansas Counselfor Petitioner Commonwealth ofKentucky Jeff Landry ffLandry Bill Schuette & Attorney General of Louisiana Elizabeth B. Murill Solicitor General Counsel ofRecord Steven B. "Beaux" Jones Assistant Attorney General Environmental Section - Civil Division 1885 N. Third Street Baton Rouge, LA 70804 Tel: (225)326-6085 Fax: (225)326-6099 MurrillE@ag.louisiana.gov Counselfor Petitioner State of Louisiana Suite 118 Frankfort, KY 40601 2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00098 ADD-100 Sfmt 8010 Fmt 8010 Q:\40\40V7.TXT 31 (Page 317 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 lpowell on DSK54DXVN1OFR with $$_JOB Environmental Protection Agency Page 104 of 139 § 60.16 the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, he shall notify the Administrator of the proposed replacements. The notice must be postmarked 60 days (or as soon as practicable) before construction of the replacements is commenced and must include the following information: (1) Name and address of the owner or operator. (2) The location of the existing facility. (3) A brief description of the existing facility and the components which are to be replaced. (4) A description of the existing air pollution control equipment and the proposed air pollution control equipment. (5) An estimate of the fixed capital cost of the replacements and of constructing a comparable entirely new facility. (6) The estimated life of the existing facility after the replacements. (7) A discussion of any economic or technical limitations the facility may have in complying with the applicable standards of performance after the proposed replacements. (e) The Administrator will determine, within 30 days of the receipt of the notice required by paragraph (d) of this section and any additional information he may reasonably require, whether the proposed replacement constitutes reconstruction. (f) The Administrator’s determination under paragraph (e) shall be based on: (1) The fixed capital cost of the replacements in comparison to the fixed capital cost that would be required to construct a comparable entirely new facility; (2) The estimated life of the facility after the replacements compared to the life of a comparable entirely new facility; (3) The extent to which the components being replaced cause or contribute to the emissions from the facility; and (4) Any economic or technical limitations on compliance with applicable standards of performance which are inherent in the proposed replacements. (g) Individual subparts of this part may include specific provisions which refine and delimit the concept of reconstruction set forth in this section. [40 FR 58420, Dec. 16, 1975] § 60.16 Priority list. PRIORITIZED MAJOR SOURCE CATEGORIES Priority Number 1 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 45. 46. Source Category Synthetic Organic Chemical Manufacturing Industry (SOCMI) and Volatile Organic Liquid Storage Vessels and Handling Equipment (a) SOCMI unit processes (b) Volatile organic liquid (VOL) storage vessels and handling equipment (c) SOCMI fugitive sources (d) SOCMI secondary sources Industrial Surface Coating: Cans Petroleum Refineries: Fugitive Sources Industrial Surface Coating: Paper Dry Cleaning (a) Perchloroethylene (b) Petroleum solvent Graphic Arts Polymers and Resins: Acrylic Resins Mineral Wool (Deleted) Stationary Internal Combustion Engines Industrial Surface Coating: Fabric Industrial-Commercial-Institutional Steam Generating Units. Incineration: Non-Municipal (Deleted) Non-Metallic Mineral Processing Metallic Mineral Processing Secondary Copper (Deleted) Phosphate Rock Preparation Foundries: Steel and Gray Iron Polymers and Resins: Polyethylene Charcoal Production Synthetic Rubber (a) Tire manufacture (b) SBR production Vegetable Oil Industrial Surface Coating: Metal Coil Petroleum Transportation and Marketing By-Product Coke Ovens Synthetic Fibers Plywood Manufacture Industrial Surface Coating: Automobiles Industrial Surface Coating: Large Appliances Crude Oil and Natural Gas Production Secondary Aluminum Potash (Deleted) Lightweight Aggregate Industry: Clay, Shale, and Slate 2 Glass Gypsum Sodium Carbonate Secondary Zinc (Deleted) Polymers and Resins: Phenolic Polymers and Resins: Urea-Melamine Ammonia (Deleted) Polymers and Resins: Polystyrene Polymers and Resins: ABS-SAN Resins Fiberglass Polymers and Resins: Polypropylene Textile Processing Asphalt Processing and Asphalt Roofing Manufacture Brick and Related Clay Products 89 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00099 ADD-101 Sfmt 8010 Fmt 8010 Q:\40\40V7.TXT 31 (Page 318 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 Pt. 60, Subpt. A, Table 1 40 CFR Ch. I (7–1–15 Edition) time periods or deadlines may be changed by mutual agreement between the owner or operator and the Administrator. An owner or operator who wishes to request a change in a time period or postmark deadline for a particular requirement shall request the adjustment in writing as soon as practicable before the subject activity is required to take place. The owner or operator shall include in the request whatever information he or she considers useful to convince the Administrator that an adjustment is warranted. (3) If, in the Administrator’s judgment, an owner or operator’s request for an adjustment to a particular time period or postmark deadline is warranted, the Administrator will approve the adjustment. The Administrator will notify the owner or operator in writing of approval or disapproval of the request for an adjustment within 15 calendar days of receiving sufficient information to evaluate the request. (4) If the Administrator is unable to meet a specified deadline, he or she will notify the owner or operator of any significant delay and inform the owner or operator of the amended schedule. [59 FR 12428, Mar. 16, 1994, as amended at 64 FR 7463, Feb. 12, 1998] TABLE 1 TO SUBPART A OF PART 60—DETECTION SENSITIVITY LEVELS (GRAMS PER HOUR) Monitoring frequency per subpart a Detection sensitivity level Bi-Monthly ...................................................... Semi-Quarterly ............................................... Monthly .......................................................... 60 85 100 a When this alternative work practice is used to identify leaking equipment, the owner or operator must choose one of the monitoring frequencies listed in this table in lieu of the monitoring frequency specified in the applicable subpart. Bimonthly means every other month. Semi-quarterly means twice per quarter. Monthly means once per month. [73 FR 78211, Dec. 22, 2008] Subpart B—Adoption and Submittal of State Plans for Designated Facilities lpowell on DSK54DXVN1OFR with $$_JOB Page 105 of 139 SOURCE: 40 FR 53346, Nov. 17, 1975, unless otherwise noted. § 60.20 Applicability. The provisions of this subpart apply to States upon publication of a final guideline document under § 60.22(a). § 60.21 Definitions. Terms used but not defined in this subpart shall have the meaning given them in the Act and in subpart A: (a) Designated pollutant means any air pollutant, the emissions of which are subject to a standard of performance for new stationary sources, but for which air quality criteria have not been issued and that is not included on a list published under section 108(a) or section 112(b)(1)(A) of the Act. (b) Designated facility means any existing facility (see § 60.2(aa)) which emits a designated pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility (see § 60.2(e)). (c) Plan means a plan under section 111(d) of the Act which establishes emission standards for designated pollutants from designated facilities and provides for the implementation and enforcement of such emission standards. (d) Applicable plan means the plan, or most recent revision thereof, which has been approved under § 60.27(b) or promulgated under § 60.27(d). (e) Emission guideline means a guideline set forth in subpart C of this part, or in a final guideline document published under § 60.22(a), which reflects the degree of emission reduction achievable through the application of the best system of emission reduction which (taking into account the cost of such reduction) the Administrator has determined has been adequately demonstrated for designated facilities. (f) Emission standard means a legally enforceable regulation setting forth an allowable rate of emissions into the atmosphere, establishing an allowance system, or prescribing equipment specifications for control of air pollution emissions. (g) Compliance schedule means a legally enforceable schedule specifying a date or dates by which a source or category of sources must comply with specific emission standards contained in a 108 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00118 ADD-102 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 319 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 Environmental Protection Agency § 60.22 plan or with any increments of progress to achieve such compliance. (h) Increments of progress means steps to achieve compliance which must be taken by an owner or operator of a designated facility, including: (1) Submittal of a final control plan for the designated facility to the appropriate air pollution control agency; (2) Awarding of contracts for emission control systems or for process modifications, or issuance of orders for the purchase of component parts to accomplish emission control or process modification; (3) Initiation of on-site construction or installation of emission control equipment or process change; (4) Completion of on-site construction or installation of emission control equipment or process change; and (5) Final compliance. (i) Region means an air quality control region designated under section 107 of the Act and described in part 81 of this chapter. (j) Local agency means any local governmental agency. [40 FR 53346, Nov. 17, 1975, as amended at 70 FR 28649, May 18, 2005; 77 FR 9447, Feb. 16, 2012] lpowell on DSK54DXVN1OFR with $$_JOB Page 106 of 139 § 60.22 Publication of guideline documents, emission guidelines, and final compliance times. (a) Concurrently upon or after proposal of standards of performance for the control of a designated pollutant from affected facilities, the Administrator will publish a draft guideline document containing information pertinent to control of the designated pollutant form designated facilities. Notice of the availability of the draft guideline document will be published in the FEDERAL REGISTER and public comments on its contents will be invited. After consideration of public comments and upon or after promulgation of standards of performance for control of a designated pollutant from affected facilities, a final guideline document will be published and notice of its availability will be published in the FEDERAL REGISTER. (b) Guideline documents published under this section will provide information for the development of State plans, such as: (1) Information concerning known or suspected endangerment of public health or welfare caused, or contributed to, by the designated pollutant. (2) A description of systems of emission reduction which, in the judgment of the Administrator, have been adequately demonstrated. (3) Information on the degree of emission reduction which is achievable with each system, together with information on the costs and environmental effects of applying each system to designated facilities. (4) Incremental periods of time normally expected to be necessary for the design, installation, and startup of identified control systems. (5) An emission guideline that reflects the application of the best system of emission reduction (considering the cost of such reduction) that has been adequately demonstrated for designated facilities, and the time within which compliance with emission standards of equivalent stringency can be achieved. The Administrator will specify different emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate. (6) Such other available information as the Administrator determines may contribute to the formulation of State plans. (c) Except as provided in paragraph (d)(1) of this section, the emission guidelines and compliance times referred to in paragraph (b)(5) of this section will be proposed for comment upon publication of the draft guideline document, and after consideration of comments will be promulgated in subpart C of this part with such modifications as may be appropriate. (d)(1) If the Administrator determines that a designated pollutant may cause or contribute to endangerment of public welfare, but that adverse effects on public health have not been demonstrated, he will include the determination in the draft guideline document and in the FEDERAL REGISTER notice of its availability. Except as provided in paragraph (d)(2) of this section, paragraph (c) of this section shall be inapplicable in such cases. 109 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00119 ADD-103 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 320 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 § 60.23 40 CFR Ch. I (7–1–15 Edition) (2) If the Administrator determines at any time on the basis of new information that a prior determination under paragraph (d)(1) of this section is incorrect or no longer correct, he will publish notice of the determination in the FEDERAL REGISTER, revise the guideline document as necessary under paragraph (a) of this section, and propose and promulgate emission guidelines and compliance times under paragraph (c) of this section. [40 FR 53346, Nov. 17, 1975, as amended at 54 FR 52189, Dec. 20, 1989] lpowell on DSK54DXVN1OFR with $$_JOB Page 107 of 139 § 60.23 Adoption and submittal of State plans; public hearings. (a)(1) Unless otherwise specified in the applicable subpart, within 9 months after notice of the availability of a final guideline document is published under § 60.22(a), each State shall adopt and submit to the Administrator, in accordance with § 60.4 of subpart A of this part, a plan for the control of the designated pollutant to which the guideline document applies. (2) Within nine months after notice of the availability of a final revised guideline document is published as provided in § 60.22(d)(2), each State shall adopt and submit to the Administrator any plan revision necessary to meet the requirements of this subpart. (b) If no designated facility is located within a State, the State shall submit a letter of certification to that effect to the Administrator within the time specified in paragraph (a) of this section. Such certification shall exempt the State from the requirements of this subpart for that designated pollutant. (c)(1) Except as provided in paragraphs (c)(2) and (c)(3) of this section, the State shall, prior to the adoption of any plan or revision thereof, conduct one or more public hearings within the State on such plan or plan revision. (2) No hearing shall be required for any change to an increment of progress in an approved compliance schedule unless the change is likely to cause the facility to be unable to comply with the final compliance date in the schedule. (3) No hearing shall be required on an emission standard in effect prior to the effective date of this subpart if it was adopted after a public hearing and is at least as stringent as the corresponding emission guideline specified in the applicable guideline document published under § 60.22(a). (d) Any hearing required by paragraph (c) of this section shall be held only after reasonable notice. Notice shall be given at least 30 days prior to the date of such hearing and shall include: (1) Notification to the public by prominently advertising the date, time, and place of such hearing in each region affected; (2) Availability, at the time of public announcement, of each proposed plan or revision thereof for public inspection in at least one location in each region to which it will apply; (3) Notification to the Administrator; (4) Notification to each local air pollution control agency in each region to which the plan or revision will apply; and (5) In the case of an interstate region, notification to any other State included in the region. (e) The State shall prepare and retain, for a minimum of 2 years, a record of each hearing for inspection by any interested party. The record shall contain, as a minimum, a list of witnesses together with the text of each presentation. (f) The State shall submit with the plan or revision: (1) Certification that each hearing required by paragraph (c) of this section was held in accordance with the notice required by paragraph (d) of this section; and (2) A list of witnesses and their organizational affiliations, if any, appearing at the hearing and a brief written summary of each presentation or written submission. (g) Upon written application by a State agency (through the appropriate Regional Office), the Administrator may approve State procedures designed to insure public participation in the matters for which hearings are required and public notification of the opportunity to participate if, in the judgment of the Administrator, the procedures, although different from the requirements of this subpart, in fact 110 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00120 ADD-104 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 321 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 Environmental Protection Agency § 60.24 provide for adequate notice to and participation of the public. The Administrator may impose such conditions on his approval as he deems necessary. Procedures approved under this section shall be deemed to satisfy the requirements of this subpart regarding procedures for public hearings. [40 FR 53346, Nov. 17, 1975, as amended at 60 FR 65414, Dec. 19, 1995] lpowell on DSK54DXVN1OFR with $$_JOB Page 108 of 139 § 60.24 Emission standards and compliance schedules. (a) Each plan shall include emission standards and compliance schedules. (b) (1) Emission standards shall either be based on an allowance system or prescribe allowable rates of emissions except when it is clearly impracticable. Such cases will be identified in the guideline documents issued under § 60.22. Where emission standards prescribing equipment specifications are established, the plan shall, to the degree possible, set forth the emission reductions achievable by implementation of such specifications, and may permit compliance by the use of equipment determined by the State to be equivalent to that prescribed. (2) Test methods and procedures for determining compliance with the emission standards shall be specified in the plan. Methods other than those specified in appendix A to this part may be specified in the plan if shown to be equivalent or alternative methods as defined in § 60.2 (t) and (u). (3) Emission standards shall apply to all designated facilities within the State. A plan may contain emission standards adopted by local jurisdictions provided that the standards are enforceable by the State. (c) Except as provided in paragraph (f) of this section, where the Administrator has determined that a designated pollutant may cause or contribute to endangerment of public health, emission standards shall be no less stringent than the corresponding emission guideline(s) specified in subpart C of this part, and final compliance shall be required as expeditiously as practicable but no later than the compliance times specified in subpart C of this part. (d) Where the Administrator has determined that a designated pollutant may cause or contribute to endangerment of public welfare but that adverse effects on public health have not been demonstrated, States may balance the emission guidelines, compliance times, and other information provided in the applicable guideline document against other factors of public concern in establishing emission standards, compliance schedules, and variances. Appropriate consideration shall be given to the factors specified in § 60.22(b) and to information presented at the public hearing(s) conducted under § 60.23(c). (e)(1) Any compliance schedule extending more than 12 months from the date required for submittal of the plan must include legally enforceable increments of progress to achieve compliance for each designated facility or category of facilities. Unless otherwise specified in the applicable subpart, increments of progress must include, where practicable, each increment of progress specified in § 60.21(h) and must include such additional increments of progress as may be necessary to permit close and effective supervision of progress toward final compliance. (2) A plan may provide that compliance schedules for individual sources or categories of sources will be formulated after plan submittal. Any such schedule shall be the subject of a public hearing held according to § 60.23 and shall be submitted to the Administrator within 60 days after the date of adoption of the schedule but in no case later than the date prescribed for submittal of the first semiannual report required by § 60.25(e). (f) Unless otherwise specified in the applicable subpart on a case-by-case basis for particular designated facilities or classes of facilities, States may provide for the application of less stringent emissions standards or longer compliance schedules than those otherwise required by paragraph (c) of this section, provided that the State demonstrates with respect to each such facility (or class of facilities): (1) Unreasonable cost of control resulting from plant age, location, or basic process design; (2) Physical impossibility of installing necessary control equipment; or 111 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00121 ADD-105 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 322 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 § 60.25 40 CFR Ch. I (7–1–15 Edition) (3) Other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable. (g) Nothing in this subpart shall be construed to preclude any State or political subdivision thereof from adopting or enforcing (1) emission standards more stringent than emission guidelines specified in subpart C of this part or in applicable guideline documents or (2) compliance schedules requiring final compliance at earlier times than those specified in subpart C or in applicable guideline documents. [40 FR 53346, Nov. 17, 1975, as amended at 60 FR 65414, Dec. 19, 1995; 65 FR 76384, Dec. 6, 2000; 70 FR 28649, May 18, 2005; 71 FR 33398, June 9, 2006; 72 FR 59204, Oct. 19, 2007; 77 FR 9447, Feb. 16, 2012] § 60.25 Emission inventories, surveillance, reports. lpowell on DSK54DXVN1OFR with $$_JOB Page 109 of 139 source (a) Each plan shall include an inventory of all designated facilities, including emission data for the designated pollutants and information related to emissions as specified in appendix D to this part. Such data shall be summarized in the plan, and emission rates of designated pollutants from designated facilities shall be correlated with applicable emission standards. As used in this subpart, ‘‘correlated’’ means presented in such a manner as to show the relationship between measured or estimated amounts of emissions and the amounts of such emissions allowable under applicable emission standards. (b) Each plan shall provide for monitoring the status of compliance with applicable emission standards. Each plan shall, as a minimum, provide for: (1) Legally enforceable procedures for requiring owners or operators of designated facilities to maintain records and periodically report to the State information on the nature and amount of emissions from such facilities, and/or such other information as may be necessary to enable the State to determine whether such facilities are in compliance with applicable portions of the plan. Submission of electronic documents shall comply with the requirements of 40 CFR part 3—(Electronic reporting). (2) Periodic inspection and, when applicable, testing of designated facilities. (c) Each plan shall provide that information obtained by the State under paragraph (b) of this section shall be correlated with applicable emission standards (see § 60.25(a)) and made available to the general public. (d) The provisions referred to in paragraphs (b) and (c) of this section shall be specifically identified. Copies of such provisions shall be submitted with the plan unless: (1) They have been approved as portions of a preceding plan submitted under this subpart or as portions of an implementation plan submitted under section 110 of the Act, and (2) The State demonstrates: (i) That the provisions are applicable to the designated pollutant(s) for which the plan is submitted, and (ii) That the requirements of § 60.26 are met. (e) The State shall submit reports on progress in plan enforcement to the Administrator on an annual (calendar year) basis, commencing with the first full report period after approval of a plan or after promulgation of a plan by the Administrator. Information required under this paragraph must be included in the annual report required by § 51.321 of this chapter. (f) Each progress report shall include: (1) Enforcement actions initiated against designated facilities during the reporting period, under any emission standard or compliance schedule of the plan. (2) Identification of the achievement of any increment of progress required by the applicable plan during the reporting period. (3) Identification of designated facilities that have ceased operation during the reporting period. (4) Submission of emission inventory data as described in paragraph (a) of this section for designated facilities that were not in operation at the time of plan development but began operation during the reporting period. (5) Submission of additional data as necessary to update the information submitted under paragraph (a) of this section or in previous progress reports. 112 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00122 ADD-106 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 323 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 Environmental Protection Agency § 60.27 (6) Submission of copies of technical reports on all performance testing on designated facilities conducted under paragraph (b)(2) of this section, complete with concurrently recorded process data. [40 FR 53346, Nov. 17, 1975, as amended at 44 FR 65071, Nov. 9, 1979; 70 FR 59887, Oct. 13, 2005] lpowell on DSK54DXVN1OFR with $$_JOB Page 110 of 139 § 60.26 Legal authority. (a) Each plan shall show that the State has legal authority to carry out the plan, including authority to: (1) Adopt emission standards and compliance schedules applicable to designated facilities. (2) Enforce applicable laws, regulations, standards, and compliance schedules, and seek injunctive relief. (3) Obtain information necessary to determine whether designated facilities are in compliance with applicable laws, regulations, standards, and compliance schedules, including authority to require recordkeeping and to make inspections and conduct tests of designated facilities. (4) Require owners or operators of designated facilities to install, maintain, and use emission monitoring devices and to make periodic reports to the State on the nature and amounts of emissions from such facilities; also authority for the State to make such data available to the public as reported and as correlated with applicable emission standards. (b) The provisions of law or regulations which the State determines provide the authorities required by this section shall be specifically identified. Copies of such laws or regulations shall be submitted with the plan unless: (1) They have been approved as portions of a preceding plan submitted under this subpart or as portions of an implementation plan submitted under section 110 of the Act, and (2) The State demonstrates that the laws or regulations are applicable to the designated pollutant(s) for which the plan is submitted. (c) The plan shall show that the legal authorities specified in this section are available to the State at the time of submission of the plan. Legal authority adequate to meet the requirements of paragraphs (a)(3) and (4) of this section may be delegated to the State under section 114 of the Act. (d) A State governmental agency other than the State air pollution control agency may be assigned responsibility for carrying out a portion of a plan if the plan demonstrates to the Administrator’s satisfaction that the State governmental agency has the legal authority necessary to carry out that portion of the plan. (e) The State may authorize a local agency to carry out a plan, or portion thereof, within the local agency’s jurisdiction if the plan demonstrates to the Administrator’s satisfaction that the local agency has the legal authority necessary to implement the plan or portion thereof, and that the authorization does not relieve the State of responsibility under the Act for carrying out the plan or portion thereof. § 60.27 Actions by the Administrator. (a) The Administrator may, whenever he determines necessary, extend the period for submission of any plan or plan revision or portion thereof. (b) After receipt of a plan or plan revision, the Administrator will propose the plan or revision for approval or disapproval. The Administrator will, within four months after the date required for submission of a plan or plan revision, approve or disapprove such plan or revision or each portion thereof. (c) The Administrator will, after consideration of any State hearing record, promptly prepare and publish proposed regulations setting forth a plan, or portion thereof, for a State if: (1) The State fails to submit a plan within the time prescribed; (2) The State fails to submit a plan revision required by § 60.23(a)(2) within the time prescribed; or (3) The Administrator disapproves the State plan or plan revision or any portion thereof, as unsatisfactory because the requirements of this subpart have not been met. (d) The Administrator will, within six months after the date required for submission of a plan or plan revision, promulgate the regulations proposed under paragraph (c) of this section with 113 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00123 ADD-107 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 324 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 § 60.28 40 CFR Ch. I (7–1–15 Edition) such modifications as may be appropriate unless, prior to such promulgation, the State has adopted and submitted a plan or plan revision which the Administrator determines to be approvable. (e)(1) Except as provided in paragraph (e)(2) of this section, regulations proposed and promulgated by the Administrator under this section will prescribe emission standards of the same stringency as the corresponding emission guideline(s) specified in the final guideline document published under § 60.22(a) and will require final compliance with such standards as expeditiously as practicable but no later than the times specified in the guideline document. (2) Upon application by the owner or operator of a designated facility to which regulations proposed and promulgated under this section will apply, the Administrator may provide for the application of less stringent emission standards or longer compliance schedules than those otherwise required by this section in accordance with the criteria specified in § 60.24(f). (f) Prior to promulgation of a plan under paragraph (d) of this section, the Administrator will provide the opportunity for at least one public hearing in either: (1) Each State that failed to hold a public hearing as required by § 60.23(c); or (2) Washington, DC or an alternate location specified in the FEDERAL REGISTER. [40 FR 53346, Nov. 17, 1975, as amended at 65 FR 76384, Dec. 6, 2000] lpowell on DSK54DXVN1OFR with $$_JOB Page 111 of 139 § 60.28 Plan revisions by the State. (a) Plan revisions which have the effect of delaying compliance with applicable emission standards or increments of progress or of establishing less stringent emission standards shall be submitted to the Administrator within 60 days after adoption in accordance with the procedures and requirements applicable to development and submission of the original plan. (b) More stringent emission standards, or orders which have the effect of accelerating compliance, may be submitted to the Administrator as plan revisions in accordance with the procedures and requirements applicable to development and submission of the original plan. (c) A revision of a plan, or any portion thereof, shall not be considered part of an applicable plan until approved by the Administrator in accordance with this subpart. § 60.29 Plan revisions by the Administrator. After notice and opportunity for public hearing in each affected State, the Administrator may revise any provision of an applicable plan if: (a) The provision was promulgated by the Administrator, and (b) The plan, as revised, will be consistent with the Act and with the requirements of this subpart. Subpart C—Emission Guidelines and Compliance Times § 60.30 Scope. The following subparts contain emission guidelines and compliance times for the control of certain designated pollutants in accordance with section 111(d) and section 129 of the Clean Air Act and subpart B of this part. (a) Subpart Ca [Reserved] (b) Subpart Cb—Municipal Waste Combustors. (c) Subpart Cc—Municipal Solid Waste Landfills. (d) Subpart Cd—Sulfuric Acid Production Plants. (e) Subpart Ce—Hospital/Medical/Infectious Waste Incinerators. [62 FR 48379, Sept. 15, 1997] § 60.31 Definitions. Terms used but not defined in this subpart have the meaning given them in the Act and in subparts A and B of this part. [42 FR 55797, Oct. 18, 1977] Subpart Ca [Reserved] 114 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00124 ADD-108 Sfmt 8006 Fmt 8010 Q:\40\40V7.TXT 31 (Page 325 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 § 60.30c Page 112 of 139 40 CFR Ch. I (7–1–15 Edition) Carbon monoxide emissions levels (parts per million by volume) a Municipal waste combustor technology Fluidized bed, mixed fuel (wood/refuse-derived fuel) ....................................................... Bubbling fluidized bed combustor ..................................................................................... Circulating fluidized bed combustor .................................................................................. Pulverized coal/refuse-derived fuel mixed fuel-fired combustor ....................................... Spreader stoker coal/refuse-derived fuel mixed fuel-fired combustor .............................. Semi-suspension refuse-derived fuel-fired combustor/wet refuse-derived fuel process conversion ...................................................................................................................... Spreader stoker fixed floor refuse-derived fuel-fired combustor/100 percent coal capable .................................................................................................................................. Averaging time (hrs) b 200 100 100 150 200 c 24 250 c 24 250 c 24 4 4 4 24 a Measured at the combustor outlet in conjunction with a measurement of oxygen concentration, corrected to 7 percent oxygen, dry basis. Calculated as an arithmetic average. b Averaging times are 4-hour or 24-hour block averages. c 24-hour block average, geometric mean. [71 FR 27334, May 10, 2006] Subpart Cc—Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills SOURCE: 61 FR 9919, Mar. 12, 1996, unless otherwise noted. § 60.30c Scope. This subpart contains emission guidelines and compliance times for the control of certain designated pollutants from certain designated municipal solid waste landfills in accordance with section 111(d) of the Act and subpart B. lpowell on DSK54DXVN1OFR with $$_JOB § 60.31c Definitions. Terms used but not defined in this subpart have the meaning given them in the Act and in subparts A, B, and WWW of this part. Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads. An MSW landfill may be publicly or privately owned. An MSW landfill may be a new MSW landfill, an existing MSW landfill or a lateral expansion. § 60.32c Designated facilities. (a) The designated facility to which the guidelines apply is each existing MSW landfill for which construction, reconstruction or modification was commenced before May 30, 1991. (b) Physical or operational changes made to an existing MSW landfill solely to comply with an emission guideline are not considered a modification or reconstruction and would not subject an existing MSW landfill to the requirements of subpart WWW [see § 60.750 of subpart WWW]. (c) For purposes of obtaining an operating permit under title V of the Act, the owner or operator of a MSW landfill subject to this subpart with a design capacity less than 2.5 million megagrams or 2.5 million cubic meters is not subject to the requirement to obtain an operating permit for the landfill under part 70 or 71 of this chapter, unless the landfill is otherwise subject to either part 70 or 71. For purposes of submitting a timely application for an operating permit under part 70 or 71, the owner or operator of a MSW landfill subject to this subpart with a design capacity greater than or equal to 2.5 million megagrams and 2.5 million cubic meters on the effective date of EPA approval of the State’s program under section 111(d) of the Act, and not otherwise subject to either part 70 or 71, becomes subject to the requirements of §§ 70.5(a)(1)(i) or 71.5(a)(1)(i) of this chapter 90 days after the effective date of such 111(d) program approval, even if the design capacity report is submitted earlier. 124 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00134 ADD-109 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 326 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 Environmental Protection Agency § 60.33c (d) When a MSW landfill subject to this subpart is closed, the owner or operator is no longer subject to the requirement to maintain an operating permit under part 70 or 71 of this chapter for the landfill if the landfill is not otherwise subject to the requirements of either part 70 or 71 and if either of the following conditions are met. (1) The landfill was never subject to the requirement for a control system under § 60.33c(c) of this subpart; or (2) The owner or operator meets the conditions for control system removal specified in § 60.752(b)(2)(v) of subpart WWW. [61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998] lpowell on DSK54DXVN1OFR with $$_JOB Page 113 of 139 § 60.33c Emission guidelines for municipal solid waste landfill emissions. (a) For approval, a State plan shall include control of MSW landfill emissions at each MSW landfill meeting the following three conditions: (1) The landfill has accepted waste at any time since November 8, 1987, or has additional design capacity available for future waste deposition; (2) The landfill has a design capacity greater than or equal to 2.5 million megagrams and 2.5 million cubic meters. The landfill may calculate design capacity in either megagrams or cubic meters for comparison with the exemption values. Any density conversions shall be documented and submitted with the design capacity report; and (3) The landfill has a nonmethane organic compound emission rate of 50 megagrams per year or more. (b) For approval, a State plan shall include the installation of a collection and control system meeting the conditions provided in § 60.752(b)(2)(ii) of this part at each MSW landfill meeting the conditions in paragraph (a) of this section. The State plan shall include a process for State review and approval of the site-specific design plans for the gas collection and control system(s). (c) For approval, a State plan shall include provisions for the control of collected MSW landfill emissions through the use of control devices meeting the requirements of paragraph (c)(1), (2), or (3) of this section, except as provided in § 60.24. (1) An open flare designed and operated in accordance with the parameters established in § 60.18; or (2) A control system designed and operated to reduce NMOC by 98 weight percent; or (3) An enclosed combustor designed and operated to reduce the outlet NMOC concentration to 20 parts per million as hexane by volume, dry basis at 3 percent oxygen, or less. (d) For approval, a State plan shall require each owner or operator of an MSW landfill having a design capacity less than 2.5 million megagrams by mass or 2.5 million cubic meters by volume to submit an initial design capacity report to the Administrator as provided in § 60.757(a)(2) of subpart WWW by the date specified in § 60.35c of this subpart. The landfill may calculate design capacity in either megagrams or cubic meters for comparison with the exemption values. Any density conversions shall be documented and submitted with the report. Submittal of the initial design capacity report shall fulfill the requirements of this subpart except as provided in paragraph (d)(1) and (d)(2) of this section. (1) The owner or operator shall submit an amended design capacity report as provided in § 60.757(a)(3) of subpart WWW. [Guidance: Note that if the design capacity increase is the result of a modification, as defined in § 60.751 of subpart WWW, that was commenced on or after May 30, 1991, the landfill will become subject to subpart WWW instead of this subpart. If the design capacity increase is the result of a change in operating practices, density, or some other change that is not a modification, the landfill remains subject to this subpart.] (2) When an increase in the maximum design capacity of a landfill with an initial design capacity less than 2.5 million megagrams or 2.5 million cubic meters results in a revised maximum design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters, the owner or operator shall comply with paragraph (e) of this section. (e) For approval, a State plan shall require each owner or operator of an MSW landfill having a design capacity equal to or greater than 2.5 million 125 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00135 ADD-110 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 327 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 § 60.34c 40 CFR Ch. I (7–1–15 Edition) megagrams and 2.5 million cubic meters to either install a collection and control system as provided in paragraph (b) of this section and § 60.752(b)(2) of subpart WWW or calculate an initial NMOC emission rate for the landfill using the procedures specified in § 60.34c of this subpart and § 60.754 of subpart WWW. The NMOC emission rate shall be recalculated annually, except as provided in § 60.757(b)(1)(ii) of subpart WWW. (1) If the calculated NMOC emission rate is less than 50 megagrams per year, the owner or operator shall: (i) Submit an annual emission report, except as provided for in § 60.757(b)(1)(ii); and (ii) Recalculate the NMOC emission rate annually using the procedures specified in § 60.754(a)(1) of subpart WWW until such time as the calculated NMOC emission rate is equal to or greater than 50 megagrams per year, or the landfill is closed. (2)(i) If the NMOC emission rate, upon initial calculation or annual recalculation required in paragraph (e)(1)(ii) of this section, is equal to or greater than 50 megagrams per year, the owner or operator shall install a collection and control system as provided in paragraph (b) of this section and § 60.752(b)(2) of subpart WWW. (ii) If the landfill is permanently closed, a closure notification shall be submitted to the Administrator as provided in § 60.35c of this subpart and § 60.757(d) of subpart WWW. [61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998; 64 FR 9261, Feb. 24, 1999] § 60.34c Test methods and procedures. For approval, a State plan shall include provisions for: the calculation of the landfill NMOC emission rate listed in § 60.754, as applicable, to determine whether the landfill meets the condition in § 60.33c(a)(3); the operational standards in § 60.753; the compliance provisions in § 60.755; and the monitoring provisions in § 60.756. lpowell on DSK54DXVN1OFR with $$_JOB Page 114 of 139 § 60.35c Reporting and recordkeeping guidelines. For approval, a State plan shall include the recordkeeping and reporting provisions listed in §§ 60.757 and 60.758, as applicable, except as provided under § 60.24. (a) For existing MSW landfills subject to this subpart the initial design capacity report shall be submitted no later than 90 days after the effective date of EPA approval of the State’s plan under section 111(d) of the Act. (b) For existing MSW landfills covered by this subpart with a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters, the initial NMOC emission rate report shall be submitted no later than 90 days after the effective date of EPA approval of the State’s plan under section 111(d) of the Act. [61 FR 9919, Mar. 12, 1996, as amended at 64 FR 9262, Feb. 24, 1999] § 60.36c Compliance times. (a) Except as provided for under paragraph (b) of this section, planning, awarding of contracts, and installation of MSW landfill air emission collection and control equipment capable of meeting the emission guidelines established under § 60.33c shall be accomplished within 30 months after the date the initial NMOC emission rate report shows NMOC emissions equal or exceed 50 megagrams per year. (b) For each existing MSW landfill meeting the conditions in § 60.33c(a)(1) and § 60.33c(a)(2) whose NMOC emission rate is less than 50 megagrams per year on the effective date of the State emission standard, installation of collection and control systems capable of meeting emission guidelines in § 60.33c shall be accomplished within 30 months of the date when the condition in § 60.33c(a)(3) is met (i.e., the date of the first annual nonmethane organic compounds emission rate which equals or exceeds 50 megagrams per year). [61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998] Subpart Cd—Emissions Guidelines and Compliance Times for Sulfuric Acid Production Units SOURCE: 60 FR 65414, Dec. 19, 1995, unless otherwise noted. 126 VerDate Sep<11>2014 14:29 Jul 31, 2015 Jkt 235157 PO 00000 Frm 00136 ADD-111 Sfmt 8002 Fmt 8010 Q:\40\40V7.TXT 31 (Page 328 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 115 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64941 tkelley on DSK3SPTVN1PROD with BOOK 2 by limiting GHG emissions through the establishment of CO2 emission guidelines for existing affected fossil fuel-fired EGUs. In addition to reducing CO2 emissions, the guidelines finalized in this rulemaking would reduce other emissions from affected EGUs that reduce generation due to higher adoption of EE and RE. These emission reductions will include SO2 and NOX, which form ambient PM2.5 and ozone in the atmosphere, and HAP, such as mercury and hydrochloric acid. In the final rule revising the annual PM2.5 NAAQS,1070 the EPA identified lowincome populations as being a vulnerable population for experiencing adverse health effects related to PM exposures. Low-income populations have been generally found to have a higher prevalence of pre-existing diseases, limited access to medical treatment, and increased nutritional deficiencies, which can increase this population’s susceptibility to PMrelated effects.1071 In areas where this rulemaking reduces exposure to PM2.5, ozone, and methylmercury, low-income populations will also benefit from such emissions reductions. The RIA for this rulemaking, included in the docket for this rulemaking, provides additional information regarding the health and ecosystem effects associated with these emission reductions. Additionally, as outlined in the community and environmental justice considerations section IX of this preamble, the EPA has taken a number of actions to help ensure that this action will not have potential disproportionately high and adverse human health or environmental effects on overburdened communities. The EPA consulted its May 2015, Guidance on Considering Environmental Justice During the Development of Regulatory Actions, when determining what actions to take.1072 As described in the community and environmental justice considerations section of this preamble the EPA also conducted a proximity analysis, which is available in the docket of this rulemaking and is 1070 ‘‘National Ambient Air Quality Standards for Particulate Matter, Final Rule,’’ 78 FR 3086 (Jan. 15, 2013). 1071 U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter (Final Report). EPA–600–R–08– 139F. National Center for Environmental Assessment—RTP Division. December. Available on the Internet at . 1072 Guidance on Considering Environmental Justice During the Development of Regulatory Actions. http://epa.gov/environmentaljustice/ resources/policy/considering-ej-in-rulemakingguide-final.pdf. May 2015. VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 discussed in section IX. Additionally, as outlined in sections I and IX of this preamble, the EPA has engaged with communities throughout this rulemaking and has devised a robust outreach strategy for continual engagement throughout the implementation phase of this rulemaking. K. Congressional Review Act (CRA) This final action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is a ‘‘major rule’’ as defined by 5 U.S.C. 804(2). XIII. Statutory Authority The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)). List of Subjects in 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements. Dated: August 3, 2015. Gina McCarthy, Administrator. For the reasons stated in the preamble, title 40, chapter I, part 60 of the Code of the Federal Regulations is amended as follows: PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 1. The authority citation for Part 60 continues to read as follows: ■ Authority: 42 U.S.C. 7401 et seq. 2. Add subpart UUUU to read as follows: ■ Subpart—UUUU Emission Guidelines for Greenhouse Gas Emissions and Compliance Times for Electric Utility Generating Units Sec. Introduction 60.5700 What is the purpose of this subpart? 60.5705 Which pollutants are regulated by this subpart? 60.5710 Am I affected by this subpart? 60.5715 What is the review and approval process for my State plan? 60.5720 What if I do not submit a plan or my plan is not approvable? 60.5725 In lieu of a State plan submittal, are there other acceptable option(s) for a PO 00000 Frm 00281 ADD-112 Sfmt 4700 Fmt 4701 State to meet its CAA section 111(d) obligations? 60.5730 Is there an approval process for a negative declaration letter? 60.5735 What authorities will not be delegated to State, local, or tribal agencies? 60.5736 Will the EPA impose any sanctions? 60.5737 What is the Clean Energy Incentive Program and how do I participate? State and Multi-State Plan Requirements 60.5740 What must I include in my federally enforceable State or multi-State plan? 60.5745 What must I include in my final plan submittal? 60.5750 Can I work with other States to develop a multi-State plan? 60.5760 What are the timing requirements for submitting my plan? 60.5765 What must I include in an initial submittal if requesting an extension for a final plan submittal? 60.5770 What schedules, performance periods, and compliance periods must I include in my plan? 60.5775 What emission standards must I include in my plan? 60.5780 What State measures may I rely upon in support of my plan? 60.5785 What is the procedure for revising my plan? 60.5790 What must I do to meet my plan obligations? Emission Rate Credit Requirements 60.5795 What affected EGUs qualify for generation of ERCs? 60.5800 What other resources qualify for issuance of ERCs? 60.5805 What is the process for the issuance of ERCs? 60.5810 What applicable requirements are there for an ERC tracking system? Mass Allocations Requirements 60.5815 What are the requirements for State allocation of allowances in a mass-based program? 60.5820 What are my allowance tracking requirements? 60.5825 What is the process for affected EGUs to demonstrate compliance in a mass-based program? Evaluation Measurement and Verification Plans and Monitoring and Verification Reports 60.5830 What are the requirements for EM&V plans for eligible resources? 60.5835 What are the requirements for M&V reports for eligible resources? Applicability of Plans to Affected EGUs 60.5840 Does this subpart directly affect EGU owners and operators in my State? 60.5845 What affected EGUs must I address in my State plan? 60.5850 What EGUs are excluded from being affected EGUs? 60.5855 What are the CO2 emission performance rates for affected EGUs? 60.5860 What applicable monitoring, recordkeeping, and reporting E:\FR\FM\23OCR3.SGM 23OCR3 (Page 329 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 116 of 139 64942 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations requirements do I need to include in my plan for affected EGUs? Recordkeeping and Reporting Requirements 60.5865 What are my recordkeeping requirements? 60.5870 What are my reporting and notification requirements? 60.5875 How do I submit information required by these emission guidelines to the EPA? Definitions 60.5880 What definitions apply to this subpart? Table 1 to Subpart UUUU of Part 60—CO2 Emission Performance Rates (Pounds of CO2 per Net MWh) Table 2 to Subpart UUUU of Part 60— Statewide Rate-based CO2 Emission Goals (Pounds of CO2 per Net MWh) Table 3 to Subpart UUUU of Part 60— Statewide Mass-based CO2 Emission Goals (Short Tons of CO2) Table 4 to Subpart UUUU of Part 60— Statewide Mass-based CO2 Emission Goals plus New Source CO2 Emission Complement (Short Tons of CO2) Introduction § 60.5700 subpart? What is the purpose of this This subpart establishes emission guidelines and approval criteria for State or multi-State plans that establish emission standards limiting greenhouse gas (GHG) emissions from an affected steam generating unit, integrated gasification combined cycle (IGCC), or stationary combustion turbine. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected EGU. These emission guidelines are developed in accordance with section 111(d) of the Clean Air Act and subpart B of this part. To the extent any requirement of this subpart is inconsistent with the requirements of subparts A or B of this part, the requirements of this subpart will apply. tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5705 Which pollutants are regulated by this subpart? (a) The pollutants regulated by this subpart are greenhouse gases. The emission guidelines for greenhouse gases established in this subpart are expressed as carbon dioxide (CO2) emission performance rates and equivalent statewide CO2 emission goals. (b) PSD and Title V Thresholds for Greenhouse Gases. (1) For the purposes of § 51.166(b)(49)(ii), with respect to GHG emissions from facilities, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 § 51.166(b)(48) and in any State Implementation Plan (SIP) approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48) of this chapter. (2) For the purposes of § 52.21(b)(50)(ii), with respect to GHG emissions from facilities regulated in the plan, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter. (3) For the purposes of § 70.2 of this chapter, with respect to greenhouse gas emissions from facilities regulated in the plan, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in § 70.2 of this chapter. (4) For the purposes of § 71.2, with respect to greenhouse gas emissions from facilities regulated in the plan, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in § 71.2 of this chapter. § 60.5710 Am I affected by this subpart? If you are the Governor of a State in the contiguous United States with one or more affected EGUs that commenced construction on or before January 8, 2014, you must submit a State or multiState plan to the U.S. Environmental Protection Agency (EPA) that implements the emission guidelines contained in this subpart. If you are the Governor of a State in the contiguous United States with no affected EGUs for which construction commenced on or before January 8, 2014, in your State, you must submit a negative declaration letter in place of the State plan. § 60.5715 What is the review and approval process for my plan? The EPA will review your plan according to § 60.27 except that under § 60.27(b) the Administrator will have 12 months after the date the final plan or plan revision (as allowed under § 60.5785) is submitted, to approve or disapprove such plan or revision or each portion thereof. If you submit an initial submittal under § 60.5765(a) in lieu of a final plan submittal the EPA will follow the procedure in § 60.5765(b). § 60.5720 What if I do not submit a plan or my plan is not approvable? (a) If you do not submit an approvable plan the EPA will develop a Federal PO 00000 Frm 00282 ADD-113 Sfmt 4700 Fmt 4701 plan for your State according to § 60.27. The Federal plan will implement the emission guidelines contained in this subpart. Owners and operators of affected EGUs not covered by an approved plan must comply with a Federal plan implemented by the EPA for the State. (b) After a Federal plan has been implemented in your State, it will be withdrawn when your State submits, and the EPA approves, a final plan. § 60.5725 In lieu of a State plan submittal, are there other acceptable option(s) for a State to meet its CAA section 111(d) obligations? A State may meet its CAA section 111(d) obligations only by submitting a final State or multi-State plan submittal or a negative declaration letter (if applicable). § 60.5730 Is there an approval process for a negative declaration letter? No. The EPA has no formal review process for negative declaration letters. Once your negative declaration letter has been received, the EPA will place a copy in the public docket and publish a notice in the Federal Register. If, at a later date, an affected EGU for which construction commenced on or before January 8, 2014 is found in your State, you will be found to have failed to submit a final plan as required, and a Federal plan implementing the emission guidelines contained in this subpart, when promulgated by the EPA, will apply to that affected EGU until you submit, and the EPA approves, a final State plan. § 60.5735 What authorities will not be delegated to State, local, or tribal agencies? The authorities that will not be delegated to State, local, or tribal agencies are specified in paragraphs (a) and (b) of this section. (a) Approval of alternatives, not already approved by this subpart, to the CO2 emission performance rates in Table 1 to this subpart established under § 60.5855. (b) Approval of alternatives, not already approved by this subpart, to the CO2 emissions goals in Tables 2, 3 and 4 to this subpart established under § 60.5855. § 60.5736 Will the EPA impose any sanctions? No. The EPA will not withhold any existing federal funds from a State on account of a State’s failure to submit, implement, or enforce an approvable plan or plan revision, or to meet any other requirements under this subpart or subpart B of this part. E:\FR\FM\23OCR3.SGM 23OCR3 (Page 330 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 117 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64943 tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5737 What is the Clean Energy Incentive Program and how do I participate? (a) This subpart establishes the Clean Energy Incentive Program (CEIP). Participation in this program is optional. The program enables States to award early action emission rate credits (ERCs) and allowances to eligible renewable energy (RE) or demand-side energy efficiency (EE) projects that generate megawatt hours (MWh) or reduce end-use energy demand during 2020 and/or 2021. Eligible projects are those that: (1) Are located in or benefit a state that has submitted a final state plan that includes requirements establishing its participation in the CEIP; and (2) Commence construction in the case of RE, or commence operation in the case of demand-side EE, following the submission of a final state plan to the EPA, or after September 6, 2018 for a state that chooses not to submit a final state plan by that date; and either (3) Generate metered MWh from any type of wind or solar resources; or (4) Result in quantified and verified electricity savings (MWh) through demand-side EE implemented in lowincome communities. (b) The EPA will award matching ERCs or allowances to States that award early action ERCs or allowances, up to a match limit equivalent to 300 million tons of CO2 emissions. The awards will be executed as follows: (1) For RE projects that generate metered MWh from wind or solar resources: For every two MWh generated, the project will receive one early action ERC (or the equivalent number of allowances) from the State, and the EPA will provide one matching ERC (or the equivalent number of allowances) to the State to award to the project. (2) For EE projects implemented in low-income communities: For every two MWh in end-use demand savings achieved, the project will receive two early action ERCs (or the equivalent number of allowances) from the State, and the EPA will provide two matching ERCs (or the equivalent number of allowances) to the State to award to the project. (c) You may participate in this program by including in your State plan a mechanism that enables issuance of early action ERCs or allowances by the State to parties effectuating reductions in the calendar years 2020 and/or 2021 in a manner that would have no impact on the emission performance of affected EGUs required to meet rate-based or mass-based emission standards during the performance periods. This VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 mechanism is not required to account for matching ERCs or allowances that may be issued to the State by the EPA. (d) If you are submitting an initial submittal by September 6, 2016, and you intend to participate in the CEIP, you must include a non-binding statement of intent to participate in the program. If you are submitting a final plan by September 6, 2016, and you intend to participate in the CEIP, your State plan must either include requirements establishing the necessary infrastructure to implement such a program and authorizing your affected EGUs to use early action allowances or ERCs as appropriate, or you must include a non-binding statement of intent as part of your supporting documentation and revise your plan to include the appropriate requirements at a later date. (e) If you intend to participate in the CEIP, your final State plan, or plan revision if applicable, must require that projects eligible under this program be evaluated, monitored, and verified, and that resulting ERCs or allowances be issued, per applicable requirements of the State plan approved by the EPA as meeting § 60.5805 through § 60.5835. State and Multi-State Plan Requirements § 60.5740 What must I include in my federally enforceable State or multi State plan? (a) You must include the components described in paragraphs (a)(1) through (5) of this section in your plan submittal. The final plan must meet the requirements and include the information required under § 60.5745. (1) Identification of affected EGUs. Consistent with § 60.25(a), you must identify the affected EGUs covered by your plan and all affected EGUs in your State that meet the applicability criteria in § 60.5845. In addition, you must include an inventory of CO2 emissions from the affected EGUs during the most recent calendar year for which data is available prior to the submission of the plan. (2) Emission standards. You must include an identification of all emission standards for each affected EGU according to § 60.5775, compliance periods for each emission standard according to § 60.5770, and a demonstration that the emission standards, when taken together, achieve the applicable CO2 emission performance rates or CO2 emission goals described in § 60.5855. Allowance systems are an acceptable form of emission standards under this subpart. (i) Your plan does not need to include corrective measures specified in PO 00000 Frm 00283 ADD-114 Sfmt 4700 Fmt 4701 paragraph (a)(2)(ii) of this section if your plan: (A) Imposes emission standards on all affected EGUs that, assuming full compliance by all affected EGUs, mathematically assure achievement of the CO2 emission performance rates in the plan for each plan period; (B) Imposes emission standards on all affected EGUS that, assuming full compliance by all affected EGUs, mathematically assure achievement of the CO2 emission goals; or (C) Imposes emission standards on all affected EGUs that, assuming full compliance by all affected EGUs, in conjunction with applicable requirements under state law for EGUs subject to subpart TTTT of this subpart, assuming the applicable requirements under state law are met by all EGUs subject to subpart TTTT of this subpart, achieve the applicable mass-based CO2 emission goals plus new source CO2 emission complement allowed for in § 60.5790(b)(5). (ii) If your plan does not meet the requirements of (a)(2)(i) or (iii) of this section, your plan must include the requirement for corrective measures to be implemented if triggered. Upon triggering corrective measures, if you do not already have them included in your approved State plan, you must submit corrective measures to EPA for approval as a plan revision per the requirements of § 60.5785(c). These corrective measures must ensure that the interim period and final period CO2 emission performance rates or CO2 emission goals are achieved by your affected EGUs, as applicable, and must achieve additional emission reductions to offset any emission performance shortfall. Your plan must include the requirement that corrective measures be triggered and implemented according to paragraphs (a)(2)(ii)(A) through (H) of this section. (A) Your plan must include a trigger for an exceedance of an interim step 1 or interim step 2 CO2 emission performance rate or CO2 emission goal by 10 percent or greater, either on average or cumulatively (if applicable). (B) Your plan must include a trigger for an exceedance of an interim step 1 goal or interim step 2 goal of 10 percent or greater based on either reported CO2 emissions with applied plus or minus net allowance export or import adjustments (if applicable), or based on the adjusted CO2 emission rate (if applicable). (C) Your plan must include a trigger for a failure to meet an interim period goal based on reported CO2 emissions with applied plus or minus net allowance export or import adjustments E:\FR\FM\23OCR3.SGM 23OCR3 (Page 331 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 118 of 139 64944 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations (if applicable), or based on the adjusted CO2 emission rate (if applicable). (D) Your plan must include a trigger for a failure to meet the interim period or any final reporting period CO2 emission performance rate or CO2 emission goal, either on average or cumulatively (as applicable). (E) Your plan must include a trigger for a failure to meet any final reporting period goal based on reported CO2 emissions with applied plus or minus net allowance export or import adjustments (if applicable). (F) Your plan must include a trigger for a failure to meet the interim period CO2 emission performance rate or CO2 emission goal based on the adjusted CO2 emission rate (if applicable). (G) Your plan must include a trigger for a failure to meet any final reporting period CO2 emission performance rate or CO2 emission goal based on the adjusted CO2 emission rate (if applicable). (H) A net allowance import adjustment represents the CO2 emissions (in tons) equal to the number of net imported CO2 allowances. This adjustment is subtracted from reported CO2 emissions. Under this adjustment, such allowances must be issued by a state with an emission budget trading program that only applies to affected EGUs (or affected EGUs plus EGUs covered by subpart TTTT of this part as applicable). A net allowance export adjustment represents the CO2 emissions (in tons) equal to the number of net exported CO2 allowances. This adjustment is added to reported CO2 emissions. (iii) If your plan relies upon State measures, in addition to or in lieu of emission standards on your affected EGUs, then the final State plan must include the requirements in paragraph (a)(3) of this section and the submittal must include the information listed in § 60.5745(a)(6). (iv) If your plan requires emission standards in addition to relying upon State measures, then you must demonstrate that the emission standards and State measures, when taken together, result in the achievement of the applicable mass-based CO2 emission goal described in § 60.5855 by your State’s affected EGUs. (3) State measures backstop. If your plan relies upon State measures, you must submit, as part of the plan in lieu of the requirements in paragraph (a)(2)(i) and (ii) of this section, a federally enforceable backstop that includes emission standards for affected EGUs that will be put into place, if there is a triggering event listed in paragraph (a)(3)(i) of this section, within 18 VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 months of the due date of the report required in § 60.5870(b). The emission standards on the affected EGUs as part of the backstop must be able to meet either the CO2 emission performance rates or mass-based or rate-based CO2 emission goal for your State during the interim and final periods. You must either submit, along with the backstop emission standards, provisions to adjust the emission standards to make up for the prior emission performance shortfall, such that no later plan revision to modify the emission standards is necessary in order to address the emission performance shortfall, or you must submit, as part of the final plan, backstop emission standards that assure affected EGUs would achieve your State’s CO2 emission performance rates or emission goals during the interim and final periods, and then later submit appropriate revisions to the backstop emission standards adjusting for the shortfall through the State plan revision process described in § 60.5785. The backstop must also include the requirements in paragraphs (a)(3)(i) through (iii) of this section, as applicable. (i) You must include a trigger for the backstop to go into effect upon: (A) A failure to meet a programmatic milestone; (B) An exceedance of 10 percent or greater of an interim step 1 goal or interim step 2 goal based on reported CO2 emissions, with applied plus or minus net allowance export or import adjustments (if applicable); (C) A failure to meet the interim period goal based on reported CO2 emissions, with applied plus or minus net allowance export or import adjustments (if applicable); or (D) A failure to meet any final reporting period goal based on reported CO2 emissions, with applied plus or minus net allowance export or import adjustments (if applicable). (ii) You may include in your plan any additional triggers so long as they do not reduce the stringency of the triggers required under paragraph (a)(3)(i) of this section. (iii) You must include a schedule for implementation of the backstop once triggered, and you must identify all necessary State administrative and technical procedures for implementing the backstop. (4) Identification of applicable monitoring, reporting, and recordkeeping requirements for each affected EGU. You must include in your plan all applicable monitoring, reporting and recordkeeping requirements for each affected EGU and PO 00000 Frm 00284 ADD-115 Sfmt 4700 Fmt 4701 the requirements must be consistent with or no less stringent than the requirements specified in § 60.5860. (5) State reporting. You must include in your plan a description of the process, contents, and schedule for State reporting to the EPA about plan implementation and progress, including information required under § 60.5870. (i) You must include in your plan a requirement for a report to be submitted by July 1, 2021, that demonstrates that the State has met, or is on track to meet, the programmatic milestone steps indicated in the timeline required in § 60.5770. (b) You must follow the requirements of subpart B of this part and demonstrate that they were met in your State plan. However, the provisions of § 60.24(f) shall not apply. § 60.5745 What must I include in my final plan submittal? (a) In addition to the components of the plan listed in § 60.5740, a final plan submittal to the EPA must include the information in paragraphs (a)(1) through (13) of this section. This information must be submitted to the EPA as part of your final plan submittal but will not be codified as part of the federally enforceable plan upon approval by EPA. (1) You must include a description of your plan approach and the geographic scope of the plan (i.e., State or multiState, geographic boundaries related to the plan elements), including, if applicable, identification of multi-State plan participants. (2) You must identify CO2 emission performance rates or equivalent statewide CO2 emission goals that your affected EGUs will achieve. If the geographic scope of your plan is a single State, then you must identify CO2 emission performance rates or emission goals according to § 60.5855. If your plan includes multiple States and you elect to set CO2 emission goals, you must identify CO2 emission goals calculated according to § 60.5750. (i) You must specify in the plan submittal the CO2 emission performance rates or emission goals that affected EGUs will meet for the interim period, each interim step, and the final period (including each final reporting period) pursuant to § 60.5770. (ii) [Reserved] (3) You must include a demonstration that the affected EGUs covered by the plan are projected to achieve the CO2 emission performance rates or CO2 emission goals described in § 60.5855. (4) You must include a demonstration that each affected EGU’s emission standard is quantifiable, non- E:\FR\FM\23OCR3.SGM 23OCR3 (Page 332 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 119 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64945 duplicative, permanent, verifiable, and enforceable according to § 60.5775. (5) If your plan includes emission standards on your affected EGUs sufficient to meet either the CO2 emission performance rates or CO2 emission goals, you must include in your plan submittal the information in paragraphs (a)(5)(i) through (v) of this section as applicable. (i) If your plan applies separate ratebased CO2 emission standards for affected EGUs (in lbs CO2/MWh) that are equal to or lower than the CO2 emission performance rates listed in Table 1 of this subpart or uniform ratebased CO2 emission standards equal to or lower than the rate-based CO2 emission goals listed in Table 2 of this subpart, then no additional demonstration is required beyond inclusion of the emission standards in the plan. (ii) If a plan applies rate-based emission standards to individual affected EGUs at a lbs CO2/MWh rate that differs from the CO2 emission performance rates in Table 1 of this subpart or the State’s rate-based CO2 emission goal in Table 2 of this subpart, then a further demonstration is required that the application of the CO2 emission standards will achieve the CO2 emission performance rates or State rate-based CO2 emission goal. You must demonstrate through a projection that the adjusted weighted average CO2 emission rate of affected EGUs, when weighted by generation (in MWh), will be equal to or less than the CO2 emission performance rates or the ratebased CO2 emission goal. This projection must address the interim period and the final period. The projection in the plan submittal must include the information listed in paragraph (a)(5)(v) of this section and in addition the following: (A) An analysis of the change in generation of affected EGUs given the compliance costs and incentives under the application of different emission rate standards across affected EGUs in a State; (B) A projection showing how generation is expected to shift between affected EGUs and across affected EGUs and non-affected EGUs over time; (C) Assumptions regarding the availability and anticipated use of the MWh of electricity generation or electricity savings from eligible resources that can be issued ERCs; (D) The specific calculation (or assumption) of how eligible resource MWh of electricity generation or savings are being used in the projection to adjust the reported CO2 emission rate of affected EGUs; VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 (E) If a state plan provides for the ability of renewable energy resources located in states with mass-based plans to be issued ERCs, consideration in the projection that such resources must meet geographic eligibility requirements, consistent with § 60.5800(a); and (F) Any other applicable assumptions used in the projection. (iii) If a plan establishes mass-based emission standards for affected EGUs that cumulatively do not exceed the State’s EPA-specified mass CO2 emission goal, then no additional demonstration is required beyond inclusion of the emission standards in the plan. (iv) If a plan applies mass-based emission standards to individual affected EGUs that cumulatively exceed the State’s EPA-specified mass CO2 emission goal, then you must include a demonstration that your mass-based emission program will be designed such that compliance by affected EGUs would achieve the State mass-based CO2 emission goals. This demonstration includes the information listed in paragraph (a)(5)(v) of this section. (v) Your plan demonstration to be included in your plan submittal, if applicable, must include the information listed in paragraphs (a)(5)(v)(A) through (L) of this section. (A) A summary of each affected EGU’s anticipated future operation characteristics, including: (1) Annual generation; (2) CO2 emissions; (3) Fuel use, fuel prices (when applicable), fuel carbon content; (4) Fixed and variable operations and maintenance costs (when applicable); (5) Heat rates; and (6) Electric generation capacity and capacity factors. (B) An identification of any planned new electric generating capacity. (C) Analytic treatment of the potential for building unplanned new electric generating capacity. (D) A timeline for implementation of EGU-specific actions (if applicable). (E) All wholesale electricity prices. (F) A geographic representation appropriate for capturing impacts and/ or changes in the electric system. (G) A time period of analysis, which must extend through at least 2031. (H) An anticipated electricity demand forecast (MWh load and MW peak demand) at the State and regional level, including the source and basis for these estimates, and, if appropriate, justification and documentation of underlying assumptions that inform the development of the demand forecast (e.g., annual economic and demand growth rate or population growth rate). PO 00000 Frm 00285 ADD-116 Sfmt 4700 Fmt 4701 (I) A demonstration that each emission standard included in your plan meets the requirements of § 60.5775. (J) Any ERC or emission allowance prices, when applicable. (K) An identification of planning reserve margins. (L) Any other applicable assumptions used in the projection. (6) If your plan relies upon State measures, in addition to or in lieu of the emission standards required by paragraph § 60.5740(a)(2), the final State plan submittal must include the information under paragraphs (a)(5)(v) and (a)(6)(i) through (v) of this section. (i) You must include a description of all the State measures the State will rely upon to achieve the applicable CO2 emission goals required under § 60.5855(e), the projected impacts of the State measures over time, the applicable State laws or regulations related to such measures, and identification of parties or entities subject to or implementing such State measures. (ii) You must include the schedule and milestones for the implementation of the State measures. If the State measures in your plan submittal rely upon measures that do not have a direct effect on the CO2 emissions measured at an affected EGU’s stack, you must also demonstrate how the minimum emission, monitoring and verification (EM&V) requirements listed under § 60.5795 that apply to those programs and projects will be met. (iii) You must demonstrate that federally enforceable emission standards for affected EGUs in conjunction with any State measures relied upon for your plan, are sufficient to achieve the mass-based CO2 emission goal for the interim period, each interim step in that interim period, the final period, and each final reporting period. In addition, you must demonstrate that each emission standard included in your plan meets the requirements of § 60.5775 and each State measure included in your plan submittal meets the requirements of § 60.5780. (iv) You must include a CO2 performance projection of your State measures that shows how the measures, whether alone or in conjunction with any federally enforceable CO2 emission standards for affected EGUs, will result in the achievement of the future CO2 performance at affected EGUs. Elements of this projection must include those specified in paragraph (a)(5)(v) of this section, as applicable, and the following for the interim period and the final period: E:\FR\FM\23OCR3.SGM 23OCR3 (Page 333 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 120 of 139 64946 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations (A) A baseline demand and supply forecast as well as the underlying assumptions and data sources of each forecast; (B) The magnitude of energy and emission impacts from all measures included in the plan and applicable assumptions; (C) An identification of Stateenforceable measures with electricity savings and RE generation, in MWh, expected for individual and collective measures and any assumptions related to the quantification of the MWh, as applicable. (7) Your plan submittal must include a demonstration that the reliability of the electrical grid has been considered in the development of your plan. (8) Your plan submittal must include a timeline with all the programmatic milestone steps the State intends to take between the time of the State plan submittal and January 1, 2022 to ensure the plan is effective as of January 1, 2022. (9) Your plan submittal must adequately demonstrate that your State has the legal authority (e.g., through regulations or legislation) and funding to implement and enforce each component of the State plan submittal, including federally enforceable emission standards for affected EGUs, and State measures as applicable. (10) Your State plan submittal must demonstrate that each interim step goal required under § 60.5855(c), will be met and include in its supporting documentation, if applicable, a description of the analytic process, tools, methods, and assumptions used to make this demonstration. (11) Your plan submittal must include certification that a hearing required under § 60.23(c)(1) on the State plan was held, a list of witnesses and their organizational affiliations, if any, appearing at the hearing, and a brief written summary of each presentation or written submission, pursuant to the requirements of § 60.23(d) and (f). (12) Your plan submittal must include documentation of any conducted community outreach and community involvement, including engagement with vulnerable communities. (13) Your plan submittal must include supporting material for your plan including: (i) Materials demonstrating the State’s legal authority and funding to implement and enforce each component of its plan, including emissions standards and/or State measures that the plan relies upon; (ii) Materials supporting that the CO2 emission performance rates or CO2 emission goals will be achieved by VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 affected EGUs identified under the plan, according to paragraph (a)(3) of this section; (iii) Materials supporting any calculations for CO2 emission goals calculated according to § 60.5855, if applicable; and (iv) Any other materials necessary to support evaluation of the plan by the EPA. (b) You must submit your final plan to the EPA electronically according to § 60.5875. § 60.5750 Can I work with other States to develop a multi-State plan? A multi-State plan must include all the required elements for a plan specified in § 60.5740(a). A multi-State plan must meet the requirements of paragraphs (a) and (b) of this section. (a) The multi-State plan must demonstrate that all affected EGUs in all participating States will meet the CO2 emission performance rates listed in Table 1 of this subpart or an equivalent CO2 emission goal according to paragraphs (a)(1) or (2) of this section. States may only follow the procedures in (a)(1) or (2) if they have functionally equivalent requirements meeting § 60.5775 and § 60.5790 included in their plans. (1) For States electing to demonstrate performance with a CO2 emission ratebased goal, the CO2 emission goals identified in the plan according to § 60.5855 will be an adjusted weighted (by net energy output) average lbs CO2/ MWh emission rate to be achieved by all affected EGUs in the multi-State area during the plan periods; or (2) For States electing to demonstrate performance with a CO2 emission massbased goal, the CO2 emission goals identified in the multi-State plan according to § 60.5855 will be total mass CO2 emissions by all affected EGUs in the multi-State area during the plan periods, representing the sum of all individual mass CO2 goals for states participating in the multi-state plan. (b) Options for submitting a multiState plan include the following: (1) States participating in a multiState plan may submit one multi-State plan submittal on behalf of all participating States. The joint submittal must be signed electronically, according to § 60.5875, by authorized officials for each of the States participating in the multi-State plan. In this instance, the joint submittal will have the same legal effect as an individual submittal for each participating State. The joint submittal must address plan components that apply jointly for all participating States and components that apply for each individual State in PO 00000 Frm 00286 ADD-117 Sfmt 4700 Fmt 4701 the multi-State plan, including necessary State legal authority to implement the plan, such as State regulations and statutes. (2) States participating in a multiState plan may submit a single plan submittal, signed by authorized officials from each participating State, which addresses common plan elements. Each participating State must, in addition, provide individual plan submittals that address State-specific elements of the multi-State plan. (3) States participating in a multiState plan may separately make individual submittals that address all elements of the multi-State plan. The plan submittals must be materially consistent for all common plan elements that apply to all participating States, and also must address individual Statespecific aspects of the multi-State plan. Each individual State plan submittal must address all required plan components in § 60.5740. (c) A State may elect to participate in more than one multi-State plan. If your State elects to participate in more than one multi-State plan then you must identify in the State plan submittal required under § 60.5745, the subset of affected EGUs that are subject to the specific multi-State plan or your State’s individual plan. An affected EGU can only be subject to one plan. (d) A State may elect to allow its affected EGUs to interact with affected EGUs in other States through massbased trading programs or a rate-based trading program without entering into a formal multi-State plan allowed for under this section, so long as such programs are part of an EPA-approved state plan and meet the requirements of paragraphs (d)(1) and (2) of this section, as applicable. (1) For States that elect to do massbased trading under this option the State must indicate in its plan that its emission budget trading program will be administered using an EPA-approved (or EPA-administered) emission and allowance tracking system. (2) For States that elect to use a ratebased trading program which allows the affected EGUs to use ERCs from other State rate-based trading programs, the plan must require affected EGUs within their State to comply with emission standards equal to the sub-category CO2 emission performance rates in Table 1 of this subpart. § 60.5760 What are the timing requirements for submitting my plan? (a) You must submit a final plan with the information required under § 60.5745 by September 6, 2016, unless you are submitting an initial submittal, E:\FR\FM\23OCR3.SGM 23OCR3 (Page 334 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 121 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64947 allowed under § 60.5765, in lieu of a final State plan submittal, according to paragraph (b) of this section. (b) For States seeking a two year extension for a final plan submittal, you must include the information in § 60.5765(a) in an initial submittal by September 6, 2016, to receive an extension to submit your final State plan submittal by September 6, 2018. (c) You must submit all information required under paragraphs (a) and (b) of this section according to the electronic reporting requirements in § 60.5875. tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5765 What must I include in an initial submittal if requesting an extension for a final plan submittal? (a) You must sufficiently demonstrate that your State is able to undertake steps and processes necessary to timely submit a final plan by the extended date of September 6, 2018, by addressing the following required components in an initial submittal by September 6, 2016, if requesting an extension for a final plan submittal: (1) An identification of final plan approach or approaches under consideration and a description of progress made to date on the final plan components; (2) An appropriate explanation of why the State requires additional time to submit a final plan by September 6, 2018; and (3) A demonstration or description of the opportunity for public comment on the initial submittal and meaningful engagement with stakeholders, including vulnerable communities, during the time in preparation of the initial submittal and the plans for engagement during development of the final plan. (b) You must submit an initial submittal allowed in paragraph (a) of this section, information required under paragraph (c) of this section (only if a State elects to submit an initial submittal to request an extension for a final plan submittal), and a final State plan submittal according to § 60.5870. If a State submits an initial submittal, an extension for a final State plan submittal is considered granted and a final State plan submittal is due according to § 60.5760(b) unless a State is notified within 90 days of the EPA receiving the initial submittal that the EPA finds the initial submittal does not meet the requirements listed in paragraph (a) of this section. If the EPA notifies the State that the initial submittal does not meet such requirements, the EPA will also notify the State that it has failed to submit the final plan required by September 6, 2016. VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 (c) If an extension for submission of a final plan has been granted, you must submit a progress report by September 6, 2017. The 2017 report must include the following: (1) A summary of the status of each component of the final plan, including an update from the 2016 initial submittal and a list of which final plan components are not complete. (2) A commitment to a plan approach (e.g., single or multi-State, rate-based or mass-based emission performance level, rate-based or mass-based emission standards), including draft or proposed legislation and/or regulations. (3) An updated comprehensive roadmap with a schedule and milestones for completing the final plan, including any updates to community engagement undertaken and planned. § 60.5770 What schedules, performance periods, and compliance periods must I include in my plan? (a) The affected EGUs covered by your plan must meet the CO2 emission requirements required under § 60.5855 for the interim period, interim steps, and the final reporting periods according to paragraph (b) of this section. You must also include in your plan compliance periods for each affected EGU regulated under the plan according to paragraphs (c) and (d) of this section. (b) Your plan must require your affected EGUs to achieve each CO2 emission performance rate or CO2 emission goal, as applicable, required under § 60.5855 over the periods according to paragraphs (b)(1) through (3) of this section. (1) The interim period. (2) Each interim step. (3) Each final reporting period. (c) The emission standards for affected EGUs regulated under the plan must include the following compliance periods: (1) For the interim period, affected EGUs must have emission standards that have compliance periods that are no longer than each interim step and are imposed for the entirety of the interim step either alone or in combination. (2) For the final period, affected EGUs must have emission standards that have compliance periods that are no longer than each final reporting period and are imposed for the entirety of the final reporting period either alone or in combination. (3) Compliance periods for each interim step and each final reporting period may take forms shorter than specified in this regulation, provided the schedules of compliance collectively end on the same schedule as each interim step and final reporting period. PO 00000 Frm 00287 ADD-118 Sfmt 4700 Fmt 4701 (d) If your plan relies upon State measures in lieu of or in addition to emission standards for affected EGUs regulated under the plan, then the performance periods must be identical to the compliance periods for affected EGUs listed in paragraphs (c)(1) through (3) of this section. § 60.5775 What emission standards must I include in my plan? (a) Emission standard(s) for affected EGUs included under your plan must be demonstrated to be quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected EGU. The plan submittal must include the methods by which each emission standard meets each of the following requirements in paragraphs (b) through (f) of this section. (b) An affected EGU’s emission standard is quantifiable if it can be reliably measured in a manner that can be replicated. (c) An affected EGU’s emission standard is verifiable if adequate monitoring, recordkeeping and reporting requirements are in place to enable the State and the Administrator to independently evaluate, measure, and verify compliance with the emission standard. (d) An affected EGU’s emission standard is non-duplicative with respect to a State plan if it is not already incorporated as an emission standard in another State plan unless incorporated in multi-State plan. (e) An affected EGU’s emission standard is permanent if the emission standard must be met for each compliance period, unless it is replaced by another emission standard in an approved plan revision, or the State demonstrates in an approvable plan revision that the emission reductions from the emission standard are no longer necessary for the State to meet its State level of performance. (f) An affected EGU’s emission standard is enforceable if: (1) A technically accurate limitation or requirement and the time period for the limitation or requirement are specified; (2) Compliance requirements are clearly defined; (3) The affected EGUs responsible for compliance and liable for violations can be identified; (4) Each compliance activity or measure is enforceable as a practical matter; and (5) The Administrator, the State, and third parties maintain the ability to enforce against violations (including if an affected EGU does not meet its emission standard based on its E:\FR\FM\23OCR3.SGM 23OCR3 (Page 335 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 122 of 139 64948 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations emissions, its allowances if it is subject to a mass-based emission standard, or its ERCs if it is subject to a rate-based emission standard) and secure appropriate corrective actions, in the case of the Administrator pursuant to CAA sections 113(a)–(h), in the case of a State, pursuant to its plan, State law or CAA section 304, as applicable, and in the case of third parties, pursuant to CAA section 304. tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5780 What State measures may I rely upon in support of my plan? You may rely upon State measures in support of your plan that are not emission standard(s) on affected EGUs, provided those State measures meet the requirements in paragraph (a) of this section. (a) Each State measure is quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected entity (e.g., entities other than affected EGUs with no federally enforceable obligations under a State plan), and your plan supporting materials include the methods by which each State measure meets each of the following requirements in paragraphs (a)(1) through (5) of this section. (1) A State measure is quantifiable with respect to an affected entity if it can be reliably measured in a manner that can be replicated. (2) A State measure is verifiable with respect to an affected entity if adequate monitoring, recordkeeping and reporting requirements are in place to enable the State to independently evaluate, measure, and verify compliance with the State measure. (3) A State measure is non-duplicative with respect to an affected entity if it is not already incorporated as a State measure or an emission standard in another State plan or State plan supporting material unless incorporated in a multi-State plan. (4) A State measure is permanent with respect to an affected entity if the State measure must be met for at least each compliance period, or unless either it is replaced by another State measure in an approved plan revision, or the State demonstrates in an approved plan revision that the emission reductions from the State measure are no longer necessary for the State’s affected EGUs to meet their mass-based CO2 emission goal. (5) A State measure is enforceable against an affected entity if: (i) A technically accurate limitation or requirement and the time period for the limitation or requirement are specified; (ii) Compliance requirements are clearly defined; VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 (iii) The affected entities responsible for compliance and liable for violations can be identified; (iv) Each compliance activity or measure is enforceable as a practical matter; and (v) The State maintains the ability to enforce violations and secure appropriate corrective actions. (b) [Reserved] § 60.5785 What is the procedure for revising my plan? (a) EPA-approved plans can be revised only with approval by the Administrator. The Administrator will approve a plan revision if it is satisfactory with respect to the applicable requirements of this subpart and any applicable requirements of subpart B of this part, including the requirement in § 60.5745(a)(3) to demonstrate achievement of the CO2 emission performance rates or CO2 emission goals in § 60.5855. If one (or more) of the elements of the plan set in § 60.5740 require revision with respect to achieving the CO2 emission performance rates or CO2 emission goals in § 60.5855, a request must be submitted to the Administrator indicating the proposed revisions to the plan to ensure the CO2 emission performance rates or CO2 emission goals are met. In addition, the following provisions in paragraphs (b) through (d) of this section may apply. (b) You may submit revisions to a plan to adjust CO2 emission goals according to § 60.5855(d). (c) If your State is required to submit a notification according to § 60.5870(d) indicating a triggering of corrective measures as described in § 60.5740(a)(2)(i) and your plan does not already include corrective measures to be implemented if triggered, you must revise your State plan to include corrective measures to be implemented. The corrective measures must ensure achievement of the CO2 emission performance rates or State CO2 emission goal. Additionally, the corrective measures must achieve additional CO2 emission reductions to offset any CO2 emission performance shortfall relative to the overall interim period or final period CO2 emission performance rate or State CO2 emission goal. The State plan revision submission must explain how the corrective measures both make up for the shortfall and address the State plan deficiency that caused the shortfall. The State must submit the revised plan and explanation to the EPA within 24 months after submitting the State report required in § 60.5870(a) indicating the CO2 emission performance deficiency in lieu of the PO 00000 Frm 00288 ADD-119 Sfmt 4700 Fmt 4701 requirements of § 60.28(a). The State must implement corrective measures within 6 months of the EPA’s approval of a plan revision adding them. The shortfall must be made up as expeditiously as practicable. (d) If your plan relies upon State measures, your backstop is triggered under § 60.5740(a)(3)(i), and your State measures plan backstop does not include a mechanism to make up the shortfall, you must revise your backstop emission standards to make up the shortfall. The shortfall must be made up as expeditiously as practicable. (e) Reliability Safety Valve: (1) In order to trigger a reliability safety valve, you must notify the EPA within 48 hours of an unforeseen, emergency situation that threatens reliability, such that your State will need a short-term modification of emission standards under a State plan for a specified affected EGU or EGUs. The EPA will consider the notification in § 60.5870(g)(1) to be an approved short-term modification to the State plan without needing to go through the full State plan revision process if the State provides a second notification to the EPA within seven days of the first notification. The short-term modification under a reliability safety valve allows modification to emission standards under the State plan for an affected EGU or EGUs for an initial period of up to 90 days. During that period of time, the affected EGU or EGUs will need to comply with the modified emission standards identified in the initial notification required under § 60.5870(g)(1) or amended in the second notification required under § 60.5870(g)(2). For the duration of the up to 90-day short-term modification, the CO2 emissions of the affected EGU or EGUs that exceed their obligations under the originally approved State plan will not be counted against the State’s CO2 emission performance rate or CO2 emission goal. The EPA reserves the right to review any such notification required under § 60.5870(g), and, in the event that the EPA finds such notification is improper, the EPA may disallow the short-term modification and affected EGUs must continue to operate under the approved State plan emission standards. As described more fully in § 60.5870(g)(3), at least seven days before the end of the initial 90-day reliability safety valve period, the State must notify the appropriate EPA regional office whether the reliability concern has been addressed and the affected EGU or EGUs can resume meeting the original emission standards established in the State plan prior to the short-term modification or whether a E:\FR\FM\23OCR3.SGM 23OCR3 (Page 336 of Total) serious, ongoing reliability issue necessitates the affected EGU or EGUs emitting beyond the amount allowed under the State plan. (2) Plan revisions submitted pursuant to § 60.5870(g)(3) must meet the requirements for State plan revisions under § 60.5785(a). § 60.5790 What must I do to meet my plan obligations? (a) To meet your plan obligations, you must demonstrate that your affected EGUs are complying with their emission standards as specified in § 60.5740, and you must demonstrate that the emission standards on affected EGUs, alone or in conjunction with any State measures, are resulting in achievement of the CO2 emission performance rates or statewide CO2 emission goals by affected EGUs using the procedures in paragraphs (b) through (d) of this section. If your plan requires the use of allowances for your affected EGUs to comply with their mass-based emission standards, you must follow the requirements under paragraph (b) of this section and § 60.5830. If your plan requires the use of ERCs for your affected EGUs to comply with their rate-based emission standards, you must follow the requirements under paragraphs (c) and (d) of this section and §§ 60.5795 through 60.5805. (b) If you submit a plan that sets a mass-based emission trading program for your affected EGUs, the State plan tkelley on DSK3SPTVN1PROD with BOOK 2 Where: CO2 emission rate = An affected EGU’s adjusted CO2 emission rate that will be used to determine compliance with the applicable CO2 emission standard. MCO2 = Measured CO2 mass in units of pounds (lbs) summed over the compliance period for an affected EGU. MWhop = Total net energy output over the compliance period for an affected EGU in units of MWh. MWhERC = ERC replacement generation for an affected EGU in units of MWh (ERCs are denominated in whole integers as specified in paragraph (d) of this section). (2) Your plan must specify that an ERC qualifies for the compliance demonstration specified in paragraph (c)(1) of this section if the ERC meets the requirements of paragraphs (c)(2)(i) through (iv) of this section. (i) An ERC must have a unique serial number. VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 must include emission standards and requirements that specify the allowance system, related compliance requirements and mechanisms, and the emission budget as appropriate. These requirements must include those listed in paragraphs (b)(1) through (5) of this section. (1) CO2 emission monitoring, reporting, and recordkeeping requirements for affected EGUs. (2) Requirements for State allocation of allowances consistent with § 60.5815. (3) Requirements for tracking of allowances, from issuance through submission for compliance, consistent with § 60.5820. (4) The process for affected EGUs to demonstrate compliance (allowance ‘‘true-up’’ with reported CO2 emissions) consistent with § 60.5825. (5) Requirements that address potential increased CO2 emissions from new sources, beyond the emissions expected from new sources if affected EGUs were given emission standards in the form of the subcategory-specific CO2 emission performance rates. You may meet this requirement by requiring one of the options under paragraphs (b)(5)(i) through (iii) of this section. (i) You may include, as part of your plan’s supporting documentation, requirements enforceable as a matter of State law regulating CO2 emissions from EGUs covered by subpart TTTT of this part under the mass-based CO2 goal plus new source CO2 emission complement applicable to your State in Table 4 of this subpart. If you choose this option, the term ‘‘mass-based CO2 goal plus new source CO2 emission complement’’ shall apply rather than ‘‘CO2 mass-based goal’’ and the term ‘‘CO2 emission goal’’ shall include ‘‘mass-based CO2 goal plus new source CO2 emission complement’’ in these emission guidelines. (ii) You may include requirements in your State plan for emission budget allowance allocation methods that align incentives to generate to affected EGUs or EGUs covered by subpart TTTT of this part that result in the affected EGUs meeting the mass-based CO2 emission goal; (iii) You may submit for the EPA’s approval, an equivalent method which requires affected EGUs to meet the mass-based CO2 emission goal. The EPA will evaluate the approvability of such an alternative method on a case by case basis. (c) If you submit a plan that sets ratebased emission standards on your affected EGUs, to meet the requirements of § 60.5775, you must follow the requirements in paragraphs (c)(1) through (4) of this section. (1) You must require the owner or operator of each affected EGU covered by your plan to calculate an adjusted CO2 emission rate to demonstrate compliance with its emission standard by factoring stack emissions and any ERCs into the following equation: (ii) An ERC must represent one MWh of actual energy generated or saved with zero associated CO2 emissions. (iii) An ERC must only be issued to an eligible resource that meets the requirements of § 60.5800 or to an affected EGU that meets the requirements of § 60.5795 and must only be issued by a State or its State agent through an EPA-approved ERC tracking system that meets the requirements of § 60.5810, or by the EPA through an EPA-administered tracking system. (iv) An ERC must be surrendered and retired only once for purpose of compliance with this regulation through an EPA-approved ERC tracking system that meets the requirements of § 60.5810, or by the EPA through an EPA-administered tracking system. (3) Your plan must specify that an ERC does not qualify for the compliance demonstration specified in paragraph (c)(1) of this section if it does not meet the requirements of paragraph (c)(2) of this section or if any State has used that same ERC for purposes of demonstrating achievement of a CO2 emission performance rate or CO2 emission goal. The plan must additionally include provisions that address requirements for revocation or adjustment that apply if an ERC issued by the State is subsequently found to have been improperly issued. (4) Your plan must include provisions either allowing for or restricting banking of ERCs between compliance periods for affected EGUs, and provisions not allowing any borrowing of any ERCs from future compliance periods by affected EGUs or eligible resources. PO 00000 Frm 00289 ADD-120 Sfmt 4700 Fmt 4701 E:\FR\FM\23OCR3.SGM 23OCR3 ER23OC15.005 USCA Case #15-1363 Document #1610010 04/22/2016 Page 123 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64949 (Page 337 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 124 of 139 64950 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations Emission Rate Credit Requirements § 60.5795 What affected EGUs qualify for generation of ERCs? tkelley on DSK3SPTVN1PROD with BOOK 2 (a) For issuance of ERCs to the affected EGUs that generate them, the plan must specify the accounting method and process for ERC issuance. For plans that require that affected EGUs meet a rate-based CO2 emission goal, where all affected EGUs have identical emission standards, you must specify the accounting method listed in paragraph (a)(1) of this section for generating ERCs. For plans that require affected EGUs to meet the CO2 emission performance rates or CO2 emission goals where affected EGUs have emission standards that are not equal for all affected EGUs, you must specify the accounting methods listed in paragraphs (a)(1) and (2) of this section for generating ERCs. (1) You must include the calculation method for determining the number of ERCs, denominated in MWh, that may be generated by and issued to an affected EGU that is in compliance with its emission standard, based on the difference between its emission standard and its reported CO2 emission rate for the compliance period; and (2) You must include the calculation method for determining the number of ERCs, denominated in MWh, that may be issued to affected EGUs that meet the definition of a stationary combustion turbine based on the displaced emissions from affected EGUs not meeting the definition of a stationary combustion turbine, resulting from the difference between its annualized net energy output in MWh for the calendar year(s) in the compliance period and its net energy output in MWh for the 2012 calendar year (January 1, 2012, through December 31, 2012). (b) Any ERCs generated through the method described as required by paragraph (a)(2) of this section must not be used by any affected EGUs other than steam generating units or IGCCs to demonstrate compliance as prescribed under § 60.5790(c)(1). (c) Any states in a multi-State plan that requires the use of ERCs for affected EGUs to comply with their emission standards must have functionally equivalent requirements pursuant to paragraphs (a)(1) and (2) of this section for generating ERCs. § 60.5800 What other resources qualify for issuance of ERCs? (a) ERCs may only be issued for generation or savings produced on or after January 1, 2022, to a resource that qualifies as an eligible resource because it meets each of the requirements in VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 paragraphs (a)(1) through (4) of this section. (1) Resources qualifying for eligibility only include resources that increased installed electrical generation nameplate capacity, or implemented new electrical savings measures, on or after January 1, 2013. If a resource had a nameplate capacity uprate, ERCs may be issued only for the difference in generation between its uprated nameplate capacity and its nameplate capacity prior to the uprate. ERCs must not be issued for generation for an uprate that followed a derate that occurred on or after January 1, 2013. A resource that is relicensed or receives a license extension is considered existing capacity and is not an eligible resource, unless it receives a capacity uprate as a result of the relicensing process that is reflected in its relicensed permit. In such a case, only the difference in nameplate capacity between its relicensed permit and its prior permit is eligible to be issued ERCs. (2) The resource must be connected to, and deliver energy to or save electricity on, the electric grid in the contiguous United States. (3) The resource must be located in either: (i) A State whose affected EGUs are subject to rate-based emission standards pursuant to this regulation; or (ii) A State with a mass-based CO2 emission goal, and the resource can demonstrate (e.g., through a power purchase agreement or contract for delivery) that the electricity generated is delivered with the intention to meet load in a State with affected EGUs which are subject to rate-based emission standards pursuant to this regulation, and was treated as a generation resource used to serve regional load that included the State whose affected EGUs are subject to rate-based emission standards. Notwithstanding any other provision of paragraph (a)(4) of this section, the only type of eligible resource in the State with mass-based emission standards is renewable generating technologies listed in (a)(4)(i) of this section. (4) The resource falls into one of the following categories of resources: (i) Renewable electric generating technologies using one of the following renewable energy resources: Wind, solar, geothermal, hydro, wave, tidal; (ii) Qualified biomass; (iii) Waste-to-energy (biogenic portion only); (iv) Nuclear power; (v) A non-affected combined heat and power (CHP) unit, including waste heat power; PO 00000 Frm 00290 ADD-121 Sfmt 4700 Fmt 4701 (vi) A demand-side EE or demandside management measure that saves electricity and is calculated on the basis of quantified ex post savings, not ‘‘projected’’ or ‘‘claimed’’ savings; or (vii) A category identified in a State plan and approved by the EPA to generate ERCs. (b) Any resource that does not meet the requirements of this subpart or an approved State plan cannot be issued ERCs for use by an affected EGU with its compliance demonstration required under § 60.5790(c). (c) ERCs may not be issued to or for any of the following: (1) New, modified, or reconstructed EGUs that are subject to subpart TTTT of this part, except CHP units that meet the requirements of a CHP unit under paragraph (a); (2) EGUs that do not meet the applicability requirements of §§ 60.5845 and 60.5850, except CHP units that meet the requirements of a CHP unit under paragraph (a); (3) Measures that reduce CO2 emissions outside the electric power sector, including, for example, GHG offset projects representing emission reductions that occur in the forestry and agriculture sectors, direct air capture, and crediting of CO2 emission reductions that occur in the transportation sector as a result of vehicle electrification; and (4) Any measure not approved by the EPA for issuance of ERCs in connection with a specific State plan. (d) You must include the appropriate requirements in paragraphs (d)(1) through (3) of this section for an applicable eligible resource in your plan. (1) If qualified biomass is an eligible resource, the plan must include a description of why the proposed feedstocks or feedstock categories should qualify as an approach for controlling increases of CO2 levels in the atmosphere as well as the proposed valuation of biogenic CO2 emissions. In addition, for sustainably-derived agricultural and forest biomass feedstocks, the state plan must adequately demonstrate that such feedstocks appropriately control increases of CO2 levels in the atmosphere and methods for adequately monitoring and verifying these feedstock sources and related sustainability practices. For all qualified biomass feedstocks, plans must specify how biogenic CO2 emissions will be monitored and reported, and identify specific EM&V, tracking and auditing approaches. (2) If waste-to-energy is an eligible resource, the plan must assess both the E:\FR\FM\23OCR3.SGM 23OCR3 (Page 338 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 125 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64951 capacity to strengthen existing or implement new waste reduction, reuse, recycling and composting programs, and measures to minimize any potential negative impacts of waste-to-energy operations on such programs. Additionally the plan must include a method for determining the proportion of total MWh generation from a wasteto-energy facility that is eligible for use in adjusting a CO2 emission rate (i.e., that which is generated from biogenic materials). (3) If carbon capture and utilization (CCU) is an eligible resource in a plan, the plan must include analysis supporting how the proposed qualifying CCU technology results in CO2 emission mitigation from affected EGUs and provide monitoring, reporting, and verification requirements to demonstrate the reductions. (e) States and areas of Indian country that do not have any affected EGUs, and other countries, may provide ERCs to adjust CO2 emissions provided they are connected to the contiguous U.S. grid and meet the other requirements for eligibility and eligible resources and the issuance of ERCs included in these emission guidelines, except that such States and other countries may not provide ERCs from resources described in § 60.5800(a)(4)(vi). tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5805 What is the process for the issuance of ERCs? If your plan uses ERCs your plan must include the process and requirements for issuance of ERCs to affected EGUs and eligible resources set forth in paragraphs (a) through (f) of this section. (a) Eligibility application. Your plan must require that, to receive ERCs, the owner or operator must submit an eligibility application to you that demonstrates that the requirements of your State plan as approved by the EPA as meeting § 60.5795 (for an affected EGU) or § 60.5800 (for an eligible resource) are met, and, in the case of an eligible resource, includes at a minimum: (1) Documentation that the eligibility application has only been submitted to you, or pursuant to an EPA-approved multi-State collaborative approach; (2) An EM&V plan that meets the requirements of the State plan as approved by the EPA as meeting § 60.5830; and (3) A verification report from an independent verifier that verifies the eligibility of the eligible resource to be issued an ERC and that the EM&V plan meets the requirements of the State plan as approved by the EPA of meeting § 60.5805. VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 (b) Registration. Your plan must require that any affected EGU or eligible resource register with an ERC tracking system that meets the requirements of § 60.5810 prior to the issuance of ERCs, and your plan must specify that you will only register an affected EGU or eligible resource after you approve its eligibility application and determine that the requirements of paragraph (a) of this section are met. (c) M&V reports. For an eligible resource registered pursuant to paragraph (b) of this section, your plan must require that, prior to issuance of ERCs by you, the owner or operator must submit the following: (1) An M&V report that meets the requirements of your State plan as approved by the EPA as meeting § 60.5835; and (2) A verification report from an independent verifier that verifies that the requirements for the M&V report are met. (e) Issuance of ERCs. Your plan must specify your procedure for issuance of ERCs based on your review of an M&V report and verification report, and must require that ERCs be issued only on the basis of energy actually generated or saved, and that only one ERC is issued for each verified MWh. (f) Tracking system. Your plan must require that ERCs may only be issued through an ERC tracking system approved as part of the State plan. (g) Error adjustment. Your plan must include a mechanism to adjust the number of ERCs issued if any are issued based on error (clerical, formula input error, etc.). (h) Qualification status of an eligible resource. Your plan must include a mechanism to temporarily or permanently revoke the qualification status of an eligible resource, such that it can no longer be issued ERCs for at least the duration that it does not meet the requirements for being issued ERCs in your State plan. (i) Qualification status of an independent verifier—(1) Eligibility. To be an independent verifier, a person must be approved by the State as: (A) An independent verifier, as defined by this regulation; and (B) Eligible to verify eligibility applications, EM&V plans, and/or M&V reports per the requirements of the approved State plan as meeting §§ 60.5830 and 60.5835 respectively. (2) Revocation of qualification. Your plan must include a mechanism to temporarily or permanently revoke the qualification status of an independent verifier, such that it can no longer verify eligibility applications, EM&V plans or M&V reports for at least the duration of PO 00000 Frm 00291 ADD-122 Sfmt 4700 Fmt 4701 the period it does not meet the requirements of your State plan. § 60.5810 What applicable requirements are there for an ERC tracking system? (a) Your plan must include provisions for an ERC tracking system, if applicable, that meets the following requirements: (1) It electronically records the issuance of ERCs, transfers of ERCs among accounts, surrender of ERCs by affected EGUs as part of a compliance demonstration, and retirement or cancellation of ERCs; and (2) It documents and provides electronic, internet-based public access to all information that supports the eligibility of eligible resources and issuance of ERCs and functionality to generate reports based on such information, which must include, for each ERC, an eligibility application, EM&V plan, M&V reports, and independent verifier verification reports. (b) If approved in a State plan, an ERC tracking system may provide for transfers of ERCs to or from another ERC tracking system approved in a State plan, or provide for transfers of ERCs to or from an EPA-administered ERC tracking system used to administer a Federal plan. Mass Allocation Requirements § 60.5815 What are the requirements for State allocation of allowances in a massbased program? (a) For a mass-based trading program, a State plan must include requirements for CO2 allowance allocations according to paragraphs (b) through (f) of this section. (b) Provisions for allocation of allowances for each compliance period prior to the beginning of the compliance period. (c) Provisions for allocation of setaside allowance, if applicable, must be established to ensure that the eligible resources must meet the same requirements for the ERC eligible resource requirements of § 60.5800, and the State must include eligibility application and verification provisions equivalent to those for ERCs in § 60.5805 and EM&V plan and M&V report provisions that meet the requirements of § 60.5830 and § 60.5835. (d) Provisions for adjusting allocations if the affected EGUs or eligible resources are incorrectly allocated CO2 allowances. (e) Provisions allowing for or restricting banking of allowances between compliance periods for affected EGUs. E:\FR\FM\23OCR3.SGM 23OCR3 (Page 339 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 126 of 139 64952 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations (f) Provisions not allowing any borrowing of allowances from future compliance periods by affected EGUs. Evaluation Measurement and Verification Plans and Monitoring and Verification Reports § 60.5820 What are my allowance tracking requirements? § 60.5830 What are the requirements for EM&V plans for eligible resources? (a) Your plan must include provisions for an allowance tracking system, if applicable, that meets the following requirements: (1) It electronically records the issuance of allowances, transfers of allowances among accounts, surrender of allowances by affected EGUs as part of a compliance demonstration, and retirement of allowances; and (2) It documents and provides electronic, internet-based public access to all information that supports the eligibility of eligible resources and issuance of set aside allowances, if applicable, and functionality to generate reports based on such information, which must include, for each set aside allowance, an eligibility application, EM&V plan, M&V reports, and independent verifier verification reports. (b) If approved in a State plan, an allowance tracking system may provide for transfers of allowances to or from another allowance tracking system approved in a State plan, or provide for transfers of allowances to or from an EPA-administered allowance tracking system used to administer a Federal plan. (a) If your plan requires your affected EGUs to meet their emission standards in accordance with § 60.5790, your plan must include requirements that any EM&V plan that is submitted in accordance with the requirements of § 60.5805, in support of the issuance of an ERC or set-aside allowance that can be used in accordance with § 60.5790, must meet the EM&V criteria approved as part of your State plan. (b) Your plan must require each EM&V plan to include identification of the eligible resource. (c) Your plan must require that an EM&V plan must contain specific criteria, as applicable to the specific eligible resource. (1) For RE resources, your plan must include requirements discussing how the generation data will be physically measured on a continuous basis using, for example, a revenue-quality meter. (2) For demand-side EE, your plan must require that each EM&V plan quantify and verify electricity savings on a retrospective (ex-post) basis using industry best-practice EM&V protocols and methods that yield accurate and reliable measurements of electricity savings. Your plan must also require each EM&V plan to include an assessment of the independent factors that influence the electricity savings, the expected life of the savings (in years), and a baseline that represents what would have happened in the absence of the demand-side EE activity. Additionally, your plan must require that each EM&V plan include a demonstration of how the industry bestpractices protocol and methods were applied to the specific activity, project, measure, or program covered in the EM&V plan, and include an explanation of why these protocols or methods were selected. EM&V plans must require eligible resources to demonstrate how all such best-practice approaches will be applied for the purposes of quantifying and verifying MWh results. Subsequent reporting of demand-side EE savings values must demonstrate and explain how the EM&V plan was followed. tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5825 What is the process for affected EGUs to demonstrate compliance in a mass-based program? (a) A plan must require an affected EGU’s owners or operators to demonstrate compliance with emission standards in a mass based program by holding an amount of allowances not less than the tons of total CO2 emissions for such compliance period from the affected EGUs in the account for the affected EGU’s emissions in the allowance tracking system required under § 60.5820 during the applicable compliance period. (b) In a mass-based trading program a plan may allow multiple affected EGUs co-located at the same facility to demonstrate that they are meeting the applicable emission standards on a facility-wide basis by the owner or operator holding enough allowances to cover the CO2 emissions of all the affected EGUs at the facility. (1) If there are not enough allowances to cover the facility’s affected EGUs’ CO2 emissions then there must be provisions for determining the compliance status of each affected EGU located at that facility. (2) [Reserved] VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 § 60.5835 What are the requirements for M&V reports for eligible resources? (a) If your plan requires your affected EGUs to meet their emission standards in accordance with § 60.5790, your plan must include requirements that any M&V report that is submitted in accordance with the requirements of PO 00000 Frm 00292 ADD-123 Sfmt 4700 Fmt 4701 § 60.5805, in support of the issuance of an ERC or set-aside allocation that can be used in accordance with § 60.5790, must meet the requirements of this section. (b) Your plan must require that each M&V report include the following: (1) For the first M&V report submitted, documentation that the energy-generating resources, energysaving measures, or practices were installed or implemented consistent with the description in the approved eligibility application required in § 60.5805(a). (2) Each M&V report submitted must include the following: (i) Identification of the time period covered by the M&V report; (ii) A description of how relevant quantification methods, protocols, guidelines, and guidance specified in the EM&V plan were applied during the reporting period to generate the quantified MWh of generation or MWh of energy savings; (iii) Documentation (including data) of the energy generation and/or energy savings from any activity, project, measure, resource, or program addressed in the EM&V plan, quantified and verified in MWh for the period covered by the M&V report, in accordance with its EM&V plan, and based on ex-post energy generation or savings; and (iv) Documentation of any change in the energy generation or savings capability of the eligible resource from the description of the resource in the approved eligibility application during the period covered by the M&V report and the date on which the change occurred, and/or demonstration that the eligible resource continued to meet the requirements of § 60.5800. Applicability of Plans to Affected EGUs § 60.5840 Does this subpart directly affect EGU owners or operators in my State? (a) This subpart does not directly affect EGU owners or operators in your State. However, affected EGU owners or operators must comply with the plan that a State or States develop to implement the emission guidelines contained in this subpart. (b) If a State does not submit a final plan to implement and enforce the emission guidelines contained in this subpart, or an initial submittal for which an extension to submit a final plan can be granted, by September 6, 2016, or the EPA disapproves a final plan, the EPA will implement and enforce a Federal plan, as provided in § 60.5720, applicable to each affected EGU within the State that commenced E:\FR\FM\23OCR3.SGM 23OCR3 (Page 340 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 127 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64953 construction on or before January 8, 2014. § 60.5845 What affected EGUs must I address in my State plan? (a) The EGUs that must be addressed by your plan are any affected steam generating unit, IGCC, or stationary combustion turbine that commenced construction on or before January 8, 2014. (b) An affected EGU is a steam generating unit, IGCC, or stationary combustion turbine that meets the relevant applicability conditions specified in paragraph (b)(1) through (3) of this section, as applicable, except as provided in § 60.5850. (1) Serves a generator or generators connected to a utility power distribution system with a nameplate capacity greater than 25 MW-net (i.e., capable of selling greater than 25 MW of electricity); (2) Has a base load rating (i.e., design heat input capacity) greater than 260 GJ/ hr (250 MMBtu/hr) heat input of fossil fuel (either alone or in combination with any other fuel); and (3) Stationary combustion turbines that meet the definition of either a combined cycle or combined heat and power combustion turbine. tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5850 What EGUs are excluded from being affected EGUs? EGUs that are excluded from being affected EGUs are: (a) EGUs that are subject to subpart TTTT of this part as a result of commencing construction after the subpart TTTT applicability date; (b) Steam generating units and IGCCs that are, and always have been, subject to a federally enforceable permit limiting annual net-electric sales to onethird or less of its potential electric output, or 219,000 MWh or less; (c) Non-fossil units (i.e., units that are capable of combusting 50 percent or more non-fossil fuel) that have always historically limited the use of fossil fuels to 10 percent or less of the annual capacity factor or are subject to a federally enforceable permit limiting fossil fuel use to 10 percent or less of the annual capacity factor; (d) Stationary combustion turbines not capable of combusting natural gas (e.g., not connected to a natural gas pipeline); (e) EGUs that are combined heat and power units that have always historically limited, or are subject to a federally enforceable permit limiting, annual net-electric sales to a utility distribution system to no more than the greater of either 219,000 MWh or the product of the design efficiency and the potential electric output; VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 (f) EGUs that serve a generator along with other steam generating unit(s), IGCC(s), or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less; (g) EGUs that are a municipal waste combustor unit that is subject to subpart Eb of this part; and (h) EGUs that are a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part. § 60.5855 What are the CO2 emission performance rates for affected EGUs? (a) You must require, in your plan, emission standards on affected EGUs to meet the CO2 emission performance rates listed in Table 1 of this subpart except as provided in paragraph (b) of this section. In addition, you must set CO2 emission performance rates for the interim steps, according to paragraph (a)(1) of this section, except as provided in paragraph (b) of this section. (1) You must set CO2 emission performance rates for your affected EGUs to meet during the interim step periods on average and as applicable for the two subcategories of affected EGUs. (2) [Reserved] (b) You may elect to require your affected EGUs to meet emission standards that differ from the CO2 emission performance rates listed in Table 1 of this subpart, provided that you demonstrate that the affected EGUs in your State will collectively meet their CO2 emission performance rate by achieving statewide emission goals that are equivalent and no less stringent than the CO2 emission performance rates listed in Table 1, and provided that your equivalent statewide CO2 emission goals take one of the following forms: (1) Average statewide rate-based CO2 emission goals listed in Table 2 of this subpart, except as provided in paragraphs (c) and (d); or (2) Cumulative statewide mass-based CO2 emission goals listed in Table 3 of this subpart, except as provided in paragraphs (c) and (d) of this section. (c) If your plan meets CO2 emission goals listed in paragraphs (b)(1) or (2) of this section you must develop your own interim step goals and final reporting period goal for your affected EGUs to meet either on average (in the case of rate-based goals) or cumulatively (in the case of mass-based goals). Additionally the following applies if you develop your own goals: (1) The interim period and interim steps CO2 emission goals must be in the PO 00000 Frm 00293 ADD-124 Sfmt 4700 Fmt 4701 same form, either both rate (in units of pounds per net MWh) or both mass (in tons); and (2) You must set interim step goals that will either on average or cumulatively meet the State’s interim period goal, as applicable to a rate-based or mass-based CO2 emission goal. (d) Your plan’s interim period and final period CO2 emission goals required to be met pursuant to paragraph (b)(1) or (2) of this section, may be changed in the plan only according to situations listed in paragraphs (d)(1) through (3) of this section. If a situation requires a plan revision, you must follow the procedures in § 60.5785 to submit a plan revision. (1) If your plan implements CO2 emission goals, you may submit a plan or plan revision, allowed in § 60.5785, to make corrections to them, subject to EPA’s approval, as a result of changes in the inventory of affected EGUs; and (2) If you elect to require your affected EGUs to meet emission standards to meet mass-based CO2 emission goals in your plan, you may elect to incorporate, as a matter of state law, the mass emissions from EGUs that are subject to subpart TTTT of this part that are considered new affected EGUs under subpart TTTT of this part. (e) If your plan relies upon State measures in addition to or in lieu of emission standards, you must only use the mass-based goals allowed for in paragraph (b)(2) of this section to demonstrate that your affected EGUs are meeting the required emissions performance. (f) Nothing in this subpart precludes an affected EGU from complying with its emission standard or you from meeting your obligations under the State plan. § 60.5860 What applicable monitoring, recordkeeping, and reporting requirements do I need to include in my plan for affected EGUs? (a) Your plan must include monitoring for affected EGUs that is no less stringent than what is described in (a)(1) through (8) of this section. (1) The owner or operator of an affected EGU (or group of affected EGUs that share a monitored common stack) that is required to meet rate-based or mass-based emission standards must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter, unless such a plan is already in place under another program that requires CO2 mass emissions to be monitored and reported according to part 75 of this chapter. (2) For rate-based emission standards, each compliance period shall include E:\FR\FM\23OCR3.SGM 23OCR3 (Page 341 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 128 of 139 64954 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations only ‘‘valid operating hours’’ in the compliance period, i.e., full or partial unit (or stack) operating hours for which: (i) ‘‘Valid data’’ (as defined in § 60.5880) are obtained for all of the parameters used to determine the hourly CO2 mass emissions (lbs). For the purposes of this subpart, substitute data recorded under part 75 of this chapter are not considered to be valid data; and (ii) The corresponding hourly net energy output value is also valid data (Note: For operating hours with no useful output, zero is considered to be a valid value). (3) For rate-based emission standards, the owner or operator of an affected EGU must measure and report the hourly CO2 mass emissions (lbs) from each affected unit using the procedures in paragraphs (a)(3)(i) through (vi) of this section, except as otherwise provided in paragraph (a)(4) of this section. (i) The owner or operator of an affected EGU must install, certify, operate, maintain, and calibrate a CO2 continuous emissions monitoring system (CEMS) to directly measure and record CO2 concentrations in the affected EGU exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system according to § 75.10(a)(3)(i) of this chapter. As an alternative to direct measurement of CO2 concentration, provided that the affected EGU does not use carbon separation (e.g., carbon capture and storage), the owner or operator of an affected EGU may use data from a certified oxygen (O2) monitor to calculate hourly average CO2 concentrations, in accordance with § 75.10(a)(3)(iii) of this chapter. However, when an O2 monitor is used this way, it only quantifies the combustion CO2; therefore, if the EGU is equipped with emission controls that produce non-combustion CO2 (e.g., from sorbent injection), this additional CO2 must be accounted for, in accordance with section 3 of appendix G to part 75 of this chapter. If CO2 concentration is measured on a dry basis, the owner or operator of the affected EGU must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. Alternatively, the owner or operator of an affected EGU may either use an appropriate fuelspecific default moisture value from § 75.11(b) or submit a petition to the Administrator under § 75.66 of this chapter for a site-specific default moisture value. (ii) For each ‘‘valid operating hour’’ (as defined in paragraph (a)(2) of this VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 section), calculate the hourly CO2 mass emission rate (tons/hr), either from Equation F–11 in Appendix F to part 75 of this chapter (if CO2 concentration is measured on a wet basis), or by following the procedure in section 4.2 of Appendix F to part 75 of this chapter (if CO2 concentration is measured on a dry basis). (iii) Next, multiply each hourly CO2 mass emission rate by the EGU or stack operating time in hours (as defined in § 72.2 of this chapter), to convert it to tons of CO2. Multiply the result by 2,000 lbs/ton to convert it to lbs. (iv) The hourly CO2 tons/hr values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under § 75.57(e) of this chapter and must be reported electronically under § 75.64(a)(6), if required by a plan. The owner or operator must use these data, or equivalent data, to calculate the hourly CO2 mass emissions. (v) Sum all of the hourly CO2 mass emissions values from paragraph (a)(3)(ii) of this section over the entire compliance period. (vi) For each continuous monitoring system used to determine the CO2 mass emissions from an affected EGU, the monitoring system must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and Appendices A and B to part 75 of this chapter. (4) The owner or operator of an affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)(3) of this section, determine the hourly CO2 mass emissions according to paragraphs (a)(4)(i) through (a)(4)(vi) of this section. (i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/hr), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. The fuel flow meter(s) used to measure the hourly fuel flow rates must meet the applicable certification and quality-assurance requirements in sections 2.1.5 and 2.1.6 of appendix D to part 75 (except for qualifying commercial billing meters). The fuel GCV must be determined in accordance with section 2.2 or 2.3 of appendix D, as applicable. (ii) For each measured hourly heat input rate, use Equation G–4 in Appendix G to part 75 of this chapter to calculate the hourly CO2 mass emission rate (tons/hr). (iii) For each ‘‘valid operating hour’’ (as defined in paragraph (a)(2) of this PO 00000 Frm 00294 ADD-125 Sfmt 4700 Fmt 4701 section), multiply the hourly tons/hr CO2 mass emission rate from paragraph (a)(4)(ii) of this section by the EGU or stack operating time in hours (as defined in § 72.2 of this chapter), to convert it to tons of CO2. Then, multiply the result by 2,000 lbs/ton to convert it to lbs. (iv) The hourly CO2 tons/hr values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under § 75.57(e) of this chapter and must be reported electronically under § 75.64(a)(6), if required by a plan. You must use these data, or equivalent data, to calculate the hourly CO2 mass emissions. (v) Sum all of the hourly CO2 mass emissions values (lb) from paragraph (a)(4)(iii) of this section over the entire compliance period. (vi) The owner or operator of an affected EGU may determine sitespecific carbon-based F-factors (Fc) using Equation F–7b in section 3.3.6 of appendix F to part 75 of this chapter, and may use these Fc values in the emissions calculations instead of using the default Fc values in the Equation G– 4 nomenclature. (5) For both rate-based and massbased standards, the owner or operator of an affected EGU (or group of affected units that share a monitored common stack) must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output. The owner or operator must use the following procedures to calculate net energy output, as appropriate for the type of affected EGU(s). (i) Determine Pnet the hourly net energy output in MWh. For rate-based standards, perform this calculation only for valid operating hours (as defined in paragraph (a)(2) of this section). For mass-based standards, perform this calculation for all unit (or stack) operating hours, i.e., full or partial hours in which any fuel is combusted. (ii) If there is no net electrical output, but there is mechanical or useful thermal output, either for a particular valid operating hour (for rate-based E:\FR\FM\23OCR3.SGM 23OCR3 (Page 342 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 129 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64955 (v) If applicable to your affected EGU (for example, for combined heat and power), you must calculate (Pt)PS using the following equation: VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 Where: Qm = Measured steam flow in kilograms (kg) (or pounds (lbs)) for the operating hour. H = Enthalpy of the steam at measured temperature and pressure (relative to SATP conditions or the energy in the condensate return line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb). CF = Conversion factor of 3.6 x 109 J/MWh or 3.413 x 106 Btu/MWh. (vi) For rate-based standards, sum all of the values of Pnet for the valid operating hours (as defined in paragraph (a)(2) of this section), over the entire compliance period. Then, divide the total CO2 mass emissions for the valid operating hours from paragraph (a)(3)(v) or (a)(4)(v) of this section, as applicable, by the sum of the Pnet values for the valid operating hours plus any ERC replacement generation (as shown in § 60.5790(c)), to determine the CO2 emissions rate (lb/net MWh) for the compliance period. (vii) For mass-based standards, sum all of the values of Pnet for all operating hours, over the entire compliance period. (6) In accordance with § 60.13(g), if two or more affected EGUs implementing the continuous emissions monitoring provisions in paragraph (a)(2) of this section share a common exhaust gas stack and are subject to the same emissions standard, the owner or operator may monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each EGU separately. If an owner or operator of an affected EGU chooses this option, the hourly net electric output for the common stack must be the sum of the hourly net electric output of the individual affected EGUs and the operating time must be expressed as ‘‘stack operating hours’’ (as defined in § 72.2 of this chapter). (7) In accordance with § 60.13(g), if the exhaust gases from an affected EGU implementing the continuous emissions monitoring provisions in paragraph (a)(2) of this section are emitted to the PO 00000 Frm 00295 ADD-126 Sfmt 4700 Fmt 4701 the following equation. All terms in the equation must be expressed in units of MWh. To convert each hourly net energy output value reported under part 75 of this chapter to MWh, multiply by the corresponding EGU or stack operating time. atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), the hourly CO2 mass emissions and the ‘‘stack operating time’’ (as defined in § 72.2 of this chapter) at each stack or duct must be monitored separately. In this case, the owner or operator of an affected EGU must determine compliance with an applicable emissions standard by summing the CO2 mass emissions measured at the individual stacks or ducts and dividing by the net energy output for the affected EGU. (8) Consistent with § 60.5775 or § 60.5780, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. Alternatively, if the EGUs are identical, you may apportion the combined hourly net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU. (b) For mass-based standards, the owner or operator of an affected EGU must determine the CO2 mass emissions (tons) for the compliance period as follows: (1) For each operating hour, calculate the hourly CO2 mass (tons) according to paragraph (a)(3) or (4) of this section, except that a complete data record is required, i.e., CO2 mass emissions must be reported for each operating hour. Therefore, substitute data values recorded under part 75 of this chapter for CO2 concentration, stack gas flow rate, stack gas moisture content, fuel flow rate and/or GCV shall be used in the calculations; and (2) Sum all of the hourly CO2 mass emissions values over the entire compliance period. (3) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously E:\FR\FM\23OCR3.SGM 23OCR3 ER23OC15.007 Where: Pnet = Net energy output of your affected EGU for each valid operating hour (as defined in 60.5860(a)(2)) in MWh. (Pe)ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. (Pe)IE = Electric energy output plus mechanical energy output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (Pe)A = Electric energy used for any auxiliary loads in MWh. (Pt)PS = Useful thermal output of steam (measured relative to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(v) of this section in MWh. (Pt)HR = Non-steam useful thermal output (measured relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. (Pt)IE = Useful thermal output (relative to SATP conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh. TDF = Electric Transmission and Distribution Factor of 0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total net energy output consist of useful thermal output on a 12-operating month rolling average basis, or 1.0 for all other affected EGUs. hour must be used in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads, net electric output shall be counted as zero for this calculation. (iv) Calculate Pnet for your affected EGU (or group of affected EGUs that share a monitored common stack) using ER23OC15.006 tkelley on DSK3SPTVN1PROD with BOOK 2 applications), or for a particular operating hour (for mass-based applications), the owner or operator of the affected EGU must still determine the net energy output for that hour. (iii) For rate-based applications, if there is no (i.e., zero) gross electrical, mechanical, or useful thermal output for a particular valid operating hour, that (Page 343 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 130 of 139 64956 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output (Pnet). The owner or operator must calculate net energy output according to paragraphs (a)(5)(i)(A) and (B) of this section. (c) Your plan must require the owner or operator of each affected EGU covered by your plan to maintain the records, as described in paragraphs (b)(1) and (2) of this section, for at least 5 years following the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record. (1) The owner or operator of an affected EGU must maintain each record on site for at least 2 years after the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record, whichever is latest, according to § 60.7. The owner or operator of an affected EGU may maintain the records off site and electronically for the remaining year(s). (2) The owner or operator of an affected EGU must keep all of the following records, in a form suitable and readily available for expeditious review: (i) All documents, data files, and calculations and methods used to demonstrate compliance with an affected EGU’s emission standard under § 60.5775. (ii) Copies of all reports submitted to the State under paragraph (c) of this section. (iii) Data that are required to be recorded by 40 CFR part 75 subpart F. (iv) Data with respect to any ERCs generated by the affected EGU or used by the affected EGU in its compliance demonstration including the information in paragraphs (c)(2)(iv)(A) and (B) of this section. (A) All documents related to any ERCs used in a compliance demonstration, including each eligibility application, EM&V plan, M&V report, and independent verifier verification report associated with the issuance of each specific ERC. (B) All records and reports relating to the surrender and retirement of ERCs for compliance with this regulation, including the date each individual ERC VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 with a unique serial identification number was surrendered and/or retired. (d) Your plan must require the owner or operator of an affected EGU covered by your plan to include in a report submitted to you at the end of each compliance period the information in paragraphs (d)(1) through (5) of this section. (1) Owners or operators of an affected EGU must include in the report all hourly CO2 emissions, for each affected EGU (or group of affected EGUs that share a monitored common stack). (2) For rate-based standards, each report must include: (i) The hourly CO2 mass emission rate values (tons/hr) and unit (or stack) operating times, (as monitored and reported according to part 75 of this chapter), for each valid operating hour in the compliance period; (ii) The net electric output and the net energy output (Pnet) values for each valid operating hour in the compliance period; (iii) The calculated CO2 mass emissions (lb) for each valid operating hour in the compliance period; (iv) The sum of the hourly net energy output values and the sum of the hourly CO2 mass emissions values, for all of the valid operating hours in the compliance period; (v) ERC replacement generation (if any), properly justified (see paragraph (c)(5) of this section); and (vi) The calculated CO2 mass emission rate for the compliance period (lbs/net MWh). (3) For mass-based standards, each report must include: (i) The hourly CO2 mass emission rate value (tons/hr) and unit (or stack) operating time, as monitored and reported according to part 75 of this chapter, for each unit or stack operating hour in the compliance period; (ii) The calculated CO2 mass emissions (tons) for each unit or stack operating hour in the compliance period; (iii) The sum of the CO2 mass emissions (tons) for all of the unit or stack operating hours in the compliance period; (iv) The net electric output and the net energy output (Pnet) values for each unit or stack operating hour in the compliance period; and (v) The sum of the hourly net energy output values for all of the unit or stack operating hours in the compliance period. (vi) Notwithstanding the requirements in paragraphs (c)(3)(i) through (c)(3)(iii) of this section, if the compliance period is a discrete number of calendar years (e.g., one year, three years), in lieu of PO 00000 Frm 00296 ADD-127 Sfmt 4700 Fmt 4701 reporting the information specified in those paragraphs, the owner or operator may report: (A) The cumulative annual CO2 mass emissions (tons) for each year of the compliance period, derived from the electronic emissions report for the fourth calendar quarter of that year, submitted to EPA under § 75.64(a) of this chapter; and (B) The sum of the cumulative annual CO2 mass emissions values from paragraph (c)(3)(v)(A) of this section, if the compliance period includes multiple years. (4) For each affected EGU’s compliance period, the report must also include the applicable emission standard and demonstration that it met the emission standard. An owner or operator must also include in the report the affected EGU’s calculated emission performance as a CO2 emission rate or cumulative mass in units of the emission standard required in §§ 60.5790(b) through (c) and 60.5855, as applicable. (5) If the owner or operator of an affected EGU is complying with an emission standard by using ERCs, they must include in the report a list of all unique ERC serial numbers that were retired in the compliance period, and, for each ERC, the date an ERC was surrendered and retired and eligible resource identification information sufficient to demonstrate that it meets the requirements of § 60.5800 and qualifies to be issued ERCs (including location, type of qualifying generation or savings, date commenced generating or saving, and date of generation or savings for which the ERC was issued). (6) If the owner or operator of an affected EGU is complying with an emission standard by using allowances, they must include in the report a list of all unique allowance serial numbers that were retired in the compliance period, and, for each allowance, the date an allowance was surrendered and retired and if the allowance was a setaside allowance the eligible resource identification information sufficient to demonstrate that it meets the requirements of § 60.5815(c) and qualifies to be issued set-aside allowances (including location, type of qualifying generation or savings, date commenced generating or saving, and date of generation or savings for which the allowance was issued). (e) The owner or operator of an affected EGU must follow any additional requirements for monitoring, recordkeeping and reporting in a plan that are required under § 60.5745(a)(4), if applicable. E:\FR\FM\23OCR3.SGM 23OCR3 (Page 344 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 131 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64957 (f) If an affected EGU captures CO2 to meet the applicable emission limit, the owner or operator must report in accordance with the requirements of 40 CFR part 98 subpart PP and either: (1) Report in accordance with the requirements of 40 CFR part 98 subpart RR, if injection occurs on-site; (2) Transfer the captured CO2 to an EGU or facility that reports in accordance with the requirements of 40 CFR part 98 subpart RR, if injection occurs off-site; or (3) Transfer the captured CO2 to a facility that has received an innovative technology waiver from EPA pursuant to paragraph (g) of this section. (g) Any person may request the Administrator to issue a waiver of the requirement that captured CO2 from an affected EGU be transferred to a facility reporting under 40 CFR part 98 subpart RR. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO2 as effectively as geologic sequestration, and that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO2, and permanence of the CO2 storage. The Administrator may test the system itself, or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology’s effectiveness, safety, and ability to store captured CO2 without release. The Administrator may grant conditional approval of a technology, the approval conditioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of releases of CO2 or other pollutants. The Administrator will provide notice to the public of any application under this provision, and provide public notice of any proposed action on a petition before the Administrator takes final action. Recordkeeping and Reporting Requirements tkelley on DSK3SPTVN1PROD with BOOK 2 § 60.5865 What are my recordkeeping requirements? (a) You must keep records of all information relied upon in support of any demonstration of plan components, plan requirements, supporting documentation, State measures, and the status of meeting the plan requirements defined in the plan for each interim step and the interim period. After 2029, States must keep records of all VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 information relied upon in support of any continued demonstration that the final CO2 emission performance rates or CO2 emissions goals are being achieved. (b) You must keep records of all data submitted by the owner or operator of each affected EGU that is used to determine compliance with each affected EGU emissions standard or requirements in an approved State plan, consistent with the affected EGU requirements listed in § 60.5860. (c) If your State has a requirement for all hourly CO2 emissions and net generation information to be used to calculate compliance with an annual emissions standard for affected EGUs, any information that is submitted by the owners or operators of affected EGUs to the EPA electronically pursuant to requirements in Part 75 meets the recordkeeping requirement of this section and you are not required to keep records of information that would be in duplicate of paragraph (b) of this section. (d) You must keep records at a minimum for 10 years, for the interim period, and 5 years, for the final period, from the date the record is used to determine compliance with an emissions standard, plan requirement, CO2 emission performance rate or CO2 emissions goal. Each record must be in a form suitable and readily available for expeditious review. § 60.5870 What are my reporting and notification requirements? (a) In lieu of the annual report required under § 60.25(e) and (f) of this part, you must report the information in paragraphs (b) through (f) of this section. (b) You must submit a report covering each interim step within the interim period and each of the final 2-calendar year periods due no later than July 1 of the year following the end of the period. The interim period reporting starts with a report covering interim step 1 due no later than July 1, 2025. The final period reports start with a biennial report covering the first final reporting period (which is due by July 1, 2032), a 2-calendar year average of emissions or cumulative sum of emissions used to determine compliance with the final CO2 emission performance rate or CO2 emission goal (as applicable). The report must include the information in paragraphs (b)(1) through (4) of this section. (1) The report must include the emissions performance achieved by all affected EGUs during the reporting period, consistent with the plan approach according to § 60.5745(a), and identification of whether each affected PO 00000 Frm 00297 ADD-128 Sfmt 4700 Fmt 4701 EGU is in compliance with its emission standard and whether the collective of all affected EGUs covered by the State are on schedule to meet the applicable CO2 emission performance rate or emission goal during the performance periods and compliance periods, as specified in the plan. (2) The report must include a comparison of the CO2 emission performance rate or CO2 emission goal identified in the State plan for the applicable interim step period versus the actual average, cumulative, or adjusted CO2 emission performance (as applicable) achieved by all affected EGUs. (i) For interim step 3, you do not need to include a comparison between the applicable interim step 3 CO2 emission performance rate or emission goal; you must only submit the average, cumulative or adjusted CO2 emission performance (as applicable) of your affected EGUs during that period in units of your applicable CO2 emission performance rate or emission goal. (3) The report must include all other required information, as specified in your State plan according to § 60.5740(a)(5). (4) If applicable, the report must include a program review that your State has conducted that addresses all aspects of the administration of the State plan and overall program, including State evaluations and regulatory decisions regarding eligibility applications for ERC resources and M&V reports (and associated EM&V activities), and State issuance of ERCs. The program review must assess whether the program is being administered properly in accordance with the approved plan, whether reported annual MWh of generation and savings from qualified ERC resources are being properly quantified, verified, and reported in accordance with approved EM&V plans, and whether appropriate records are being maintained. The program review must also address determination of the eligibility of verifiers by the State and the conduct of independent verifiers, including the quality of verifier reviews. (c) If your plan relies upon State measures, in lieu of or in addition to emission standards, then you must submit an annual report to the EPA in addition to the reports required under paragraph (b) of this section for the interim period. In the final period, you must submit biennial reports consistent with those required under paragraph (b) of this section. The annual reports in the interim period must be submitted no later than July 1 following the end of each calendar year starting with 2022. E:\FR\FM\23OCR3.SGM 23OCR3 (Page 345 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 132 of 139 64958 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations The annual and biennial reports must include the information in paragraphs (c)(1) and (2) of this section for the preceding year or two years, as applicable. (1) You must include in your report the status of implementation of federally enforceable emission standards (if applicable) and State measures. (2) You must include information regarding the status of the periodic programmatic milestones to show progress in program implementation. The programmatic milestones with specific dates for achievement must be consistent with the State measures included in the State plan submittal. (d) If your plan includes the requirement for emission standards on your affected EGUs, then you must submit a notification, if applicable, in the report required under paragraph (b) of this section to the EPA if your affected EGUs trigger corrective measures as described in § 60.5740(a)(2)(i). If corrective measures are required and were not previously submitted with your state plan, you must follow the requirements in § 60.5785 for revising your plan to implement the corrective measures. (e) If your plan relies upon State measures, in lieu of or in addition to emission standards, than you must submit a notification as required under paragraphs (e)(1) and (2) of this section. (1) You must submit a notification in the report required under paragraph (c) of this section to the EPA if at the end of the calendar year your State did not meet a programmatic milestone included in your plan submittal. This notification must detail the implementation of the backstop required in your plan to be fully in place within 18 months of the due date of the report required in paragraph (b) of this section. In addition, the notification must describe the steps taken by the State to inform the affected EGUs in its State that the backstop has been triggered. (2) You must submit a notification in the report required under paragraph (b) of this section to the EPA if you trigger the backstop as described in § 60.5740(a)(3)(i). This notification must detail the steps that will be taken by you to implement the backstop so that it is fully in place within 18 months of the due date of the report required in paragraph (b) of this section. In addition, the notification must describe the steps taken by the State to inform the affected EGUs that the backstop has been triggered. (f) You must include in your 2029 report (which is due by July 1, 2030) the calculation of average CO2 emissions VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 rate, cumulative sum of CO2 emissions, or adjusted CO2 emissions rate (as applicable) over the interim period and a comparison of those values to your interim CO2 emission performance rate or emission goal. The calculated value must be in units consistent with the approach you set in your plan for the interim period. (g) The notifications listed in paragraphs (g)(1) through (3) of this section are required for the reliability safety valve allowed in § 60.5785(e). (1) As required under § 60.5785(e), you must submit an initial notification to the appropriate EPA regional office within 48 hours of an unforeseen, emergency situation. The initial notification must: (i) Include a full description, to the extent that it is known, of the emergency situation that is being addressed; (ii) Identify the affected EGU or EGUs that are required to run to assure reliability; and (iii) Specify the modified emission standards at which the identified EGU or EGUs will operate. (2) Within 7 days of the initial notification in § 60.5870(g)(1), the State must submit a second notification to the appropriate EPA regional office that documents the initial notification. If the State fails to submit this documentation on a timely basis, the EPA will notify the State, which must then notify the affected EGU(s) that they must operate or resume operations under the original approved State plan emission standards. This notification must include the following: (i) A full description of the reliability concern and why an unforeseen, emergency situation that threatens reliability requires the affected EGU or EGUs to operate under modified emission standards from those originally required in the State plan including discussion of why the flexibilities provided under the state’s plan are insufficient to address the concern; (ii) A description of how the State is coordinating or will coordinate with relevant reliability coordinators and planning authorities to alleviate the problem in an expedited manner; (iii) An indication of the maximum time that the State anticipates the affected EGU or EGUs will need to operate in a manner inconsistent with its or their obligations under the State’s approved plan; (iv) A written concurrence from the relevant reliability coordinator and/or planning authority confirming the existence of the imminent reliability threat and supporting the temporary PO 00000 Frm 00298 ADD-129 Sfmt 4700 Fmt 4701 modification request or an explanation of why this kind of concurrence cannot be provided; (v) The modified emission standards or levels that the affected EGU or EGU will be operating at for the remainder of the 90-day period if it has changed from the initial notification; and (vi) Information regarding any systemwide or other analysis of the reliability concern conducted by the relevant planning authority, if any. (3) At least 7 days before the end of the 90-day reliability safety valve period, the State must notify the appropriate EPA regional office that either: (i) The reliability concern has been addressed and the affected EGU or EGUs can resume meeting the original emission standards in the State plan approved prior to the short-term modification; or (ii) There still is a serious, ongoing reliability issue that necessitates the affected EGU or EGUs to emit beyond the amount allowed under the State plan. In this case, the State must provide a notification to the EPA that it will be submitting a State plan revision according to paragraph § 60.5785(a) of this section to address the reliability issue. The notification must provide the date by which a revised State plan will be submitted to EPA and documentation of the ongoing emergency with a written concurrence from the relevant reliability coordinator and/or planning authority confirming the continuing urgent need for the affected EGU or EGUs to operate beyond the requirements of the State plan and that there is no other reasonable way of addressing the ongoing reliability emergency but for the affected EGU or EGUs to operate under an alternative emission standard than originally approved under the State plan. After the initial 90-day period, any excess emissions beyond what is authorized in the original approved State plan will count against the State’s overall CO2 emission goal or emission performance rate for affected EGUs. § 60.5875 How do I submit information required by these Emission Guidelines to the EPA? (a) You must submit to the EPA the information required by these emission guidelines following the procedures in paragraphs (b) through (e) of this section. (b) All negative declarations, State plan submittals, supporting materials that are part of a State plan submittal, any plan revisions, and all State reports required to be submitted to the EPA by the State plan must be reported through EPA’s State Plan Electronic Collection E:\FR\FM\23OCR3.SGM 23OCR3 (Page 346 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 133 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64959 System (SPeCS). SPeCS is a web accessible electronic system accessed at the EPA’s Central Data Exchange (CDX) (http://www.epa.gov/cdx/). States who claim that a State plan submittal or supporting documentation includes confidential business information (CBI) must submit that information on a compact disc, flash drive, or other commonly used electronic storage media to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local Programs Group, MD C539–01, 4930 Old Page Rd., Durham, NC 27703. (c) Only a submittal by the Governor or the Governor’s designee by an electronic submission through SPeCS shall be considered an official submittal to the EPA under this subpart. If the Governor wishes to designate another responsible official the authority to submit a State plan, the EPA must be notified via letter from the Governor prior to the September 6, 2016, deadline for plan submittal so that the official will have the ability to submit the initial or final plan submittal in the SPeCS. If the Governor has previously delegated authority to make CAA submittals on the Governor’s behalf, a State may submit documentation of the delegation in lieu of a letter from the Governor. The letter or documentation must identify the designee to whom authority is being designated and must include the name and contact information for the designee and also identify the State plan preparers who will need access to SPeCS. A State may also submit the names of the State plan preparers via a separate letter prior to the designation letter from the Governor in order to expedite the State plan administrative process. Required contact information for the designee and preparers includes the person’s title, organization and email address. (d) The submission of the information by the authorized official must be in a non-editable format. In addition to the non-editable version all plan components designated as federally enforceable must also be submitted in an editable version. Following initial plan approval, States must provide the EPA with an editable copy of any submitted revision to existing approved federally enforceable plan components, including State plan backstop measures. The editable copy of any such submitted plan revision must indicate the changes made at the State level, if any, to the existing approved federally enforceable plan components, using a mechanism such as redline/strikethrough. These changes are not part of the State plan until formal approval by EPA. VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 (e) You must provide the EPA with non-editable and editable copies of any submitted revision to existing approved federally enforceable plan components, including State plan backstop measures. The editable copy of any such submitted plan revision must indicate the changes made at the State level, if any, to the existing approved federally enforceable plan components, using a mechanism such as redline/strikethrough. These changes are not part of the State plan until formal approval by EPA. Definitions § 60.5880 subpart? What definitions apply to this As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subparts A, B, and TTTT, of this part. Adjusted CO2 Emission Rate Means (1) For an affected EGU, the reported CO2 emission rate of an affected EGU, adjusted as described in § 60.5790(c)(1) to reflect any ERCs used by an affected EGU to demonstrate compliance with its CO2 emission standards; or (2) For a State (or states in a multistate plan) calculating a collective CO2 emission rate achieved under the plan, the actual CO2 emission rate during a plan reporting period of the affected EGUs subject to the rate specified in the plan, adjusted by the ERCs used for compliance by those EGUs (total CO2 mass divided by the sum of the total MWh and ERCs). Affected electric generating unit or Affected EGU means a steam generating unit, integrated gasification combined cycle (IGCC), or stationary combustion turbine that meets the relevant applicability conditions in section § 60.5845. Allowance means an authorization for each specified unit of actual CO2 emitted from an affected EGU or a facility during a specified period. Allowance system means a control program under which the owner or operator of each affected EGU is required to hold an allowance for each specified unit of CO2 emitted from that affected EGU or facility during a specified period and which limits the total amount of such allowances for a specified period and allows the transfer of such allowances. Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating. Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady-state basis, as PO 00000 Frm 00299 ADD-130 Sfmt 4700 Fmt 4701 determined by the physical design and characteristics of the EGU at ISO conditions. For a stationary combustion turbine, base load rating includes the heat input from duct burners. Biomass means biologically based material that is living or dead (e.g., trees, crops, grasses, tree litter, roots) above and below ground, and available on a renewable or recurring basis. Materials that are biologically based include non-fossilized, biodegradable organic material originating from modern or contemporarily grown plants, animals, or microorganisms (including plants, products, byproducts and residues from agriculture, forestry, and related activities and industries, as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic material). CO2 emission goal means a statewide rate-based CO2 emission goal or massbased CO2 emission goal specified in § 60.5855. Combined cycle unit means an electric generating unit that uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity. Combined heat and power unit or CHP unit, (also known as ‘‘cogeneration’’) means an electric generating unit that uses a steamgenerating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy source. Compliance period means a discrete time period for an affected EGU to comply with either an emission standard or State measure. Demand-side energy efficiency project means an installed piece of equipment or system, a modification of an existing piece of equipment or system, or a strategy intended to affect consumer electricity-use behavior, that results in a reduction in electricity use (in MWh) at an end-use facility, premises, or equipment connected to the electricity grid. Derate means a decrease in the available capacity of an electric generating unit, due to a system or equipment modification or to discounting a portion of a generating unit’s capacity for planning purposes. Eligible resource means a resource that meets the requirements of § 60.5800(a). E:\FR\FM\23OCR3.SGM 23OCR3 (Page 347 of Total) tkelley on DSK3SPTVN1PROD with BOOK 2 USCA Case #15-1363 Document #1610010 04/22/2016 Page 134 of 139 64960 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations Emission Rate Credit or ERC means a tradable compliance instrument that meets the requirements of § 60.5790(c). EM&V plan means a plan that meets the requirements of § 60.5830. ERC tracking system means a system for the issuance, surrender and retirement of ERCs that meets the requirements of § 60.5810. Final period means the period that begins on January 1, 2030, and continues thereafter. The final period is comprised of final reporting periods, each of which may be no longer than two calendar years (with a calendar year beginning on January 1 and ending on December 31). Final reporting period means an increment of plan performance within the final period, with each final reporting period being no longer than two calendar years (with a calendar year beginning on January 1 and ending on December 31), with the first final reporting period in the final period beginning on January 1, 2030, and ending no later than December 31, 2031. Fossil fuel means natural gas, petroleum, coal, and any form of solid fuel, liquid fuel, or gaseous fuel derived from such material for the purpose of creating useful heat. Heat recovery steam generating unit (HRSG) means a unit in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Independent verifier means a person (including any individual, corporation, partnership, or association) who has the appropriate technical and other qualifications to provide verification reports. The independent verifier must not have, or have had, any direct or indirect financial or other interest in the subject of its verification report or ERCs that could impact their impartiality in performing verification services. Integrated gasification combined cycle facility or IGCC means a combined cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation. Interim period means the period of eight calendar years from January 1, VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 2022, to December 31, 2029. The interim period is composed three interim steps, interim step 1, interim step 2, and interim step 3. Interim step means an increment of plan performance within the interim period. Interim step 1 means the period of three calendar years from January 1, 2022, to December 31, 2024. Interim step 2 means the period of three calendar years from January 1, 2025, to December 31, 2027. Interim step 3 means the period of two calendar years from January 1, 2028, to December 31, 2029. ISO conditions means 288 Kelvin (15 °C), 60 percent relative humidity and 101.3 kilopascals pressure. M&V report means a report that meets the requirements of § 60.5835. Mechanical output means the useful mechanical energy that is not used to operate the affected facility, generate electricity and/or thermal output, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour must be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Nameplate capacity means, starting from the initial installation, the maximum electrical generating output that a generator, prime mover, or other electric power production equipment under specific conditions designated by the manufacturer is capable of producing (in MWe, rounded to the nearest tenth) on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the equipment, or starting from the completion of any subsequent physical change resulting in an increase in the maximum electrical generating output that the equipment is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous State under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous PO 00000 Frm 00300 ADD-131 Sfmt 4700 Fmt 4701 fuels: Landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Net allowance export/import means a net transfer of CO2 allowances during an interim step, the interim period, or a final reporting period which represents the net number of CO2 allowances (issued by a State) that are transferred from the compliance accounts of affected EGUs in that state to the compliance accounts of affected EGUs in another State. This net transfer is determined based on compliance account holdings at the end of the plan performance period. Compliance account holdings, as used here, refer to the number of CO2 allowances surrendered for compliance during a plan performance period, as well as any remaining CO2 allowances held in a compliance account as of the end of a plan performance period. Net electric output means the amount of gross generation the generator(s) produce (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means: (1) The net electric or mechanical output from the affected facility, plus 100 percent of the useful thermal output measured relative to SATP conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application). (2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output; (e.g., steam delivered to an industrial process for a heating application). Programmatic milestone means the implementation of measures necessary for plan progress, including specific dates associated with such E:\FR\FM\23OCR3.SGM 23OCR3 (Page 348 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 135 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64961 implementation. Prior to January 1, 2022, programmatic milestones are applicable to all state plan approaches and measures. Subsequent to January 1, 2022, programmatic milestones are applicable to state measures. Qualified biomass means a biomass feedstock that is demonstrated as a method to control increases of CO2 levels in the atmosphere. Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 °C, 77 °F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. State agent means an entity acting on behalf of the State, with the legal authority of the State. State measures means measures that are adopted, implemented, and enforced as a matter of State law. Such measures are enforceable only per State law, and are not included in and codified as part of the federally enforceable State plan. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post-combustion emissions control technology, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment. Uprate means an increase in available electric generating unit power capacity due to a system or equipment modification. Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output), or to supply energy to a pollution control device at the affected EGU. Useful thermal output for affected EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s)) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. Valid data means quality-assured data generated by continuous monitoring systems that are installed, operated, and maintained according to part 75 of this chapter. For CEMS, the initial certification requirements in § 75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality-assured data are reported under this subpart; for on-going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before qualityassured data are reported under this subpart (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D), and for on-going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 of this chapter apply (except for qualifying commercial billing meters). Waste-to-Energy means a process or unit (e.g., solid waste incineration unit) that recovers energy from the conversion or combustion of waste stream materials, such as municipal solid waste, to generate electricity and/ or heat. TABLE 1 TO SUBPART UUUU OF PART 60—CO2 EMISSION PERFORMANCE RATES [Pounds of CO2 per net MWh] Affected EGU Interim rate Steam generating unit or integrated gasification combined cycle (IGCC) .............................................................. Stationary combustion turbine ................................................................................................................................. 1,534 832 Final rate 1,305 771 TABLE 2 TO SUBPART UUUU OF PART 60—STATEWIDE RATE-BASED CO2 EMISSION GOALS [Pounds of CO2 per net MWh] tkelley on DSK3SPTVN1PROD with BOOK 2 State Interim emission goal Alabama ................................................................................................................................... Arizona ..................................................................................................................................... Arkansas .................................................................................................................................. California .................................................................................................................................. Colorado .................................................................................................................................. Connecticut .............................................................................................................................. Delaware .................................................................................................................................. Florida ...................................................................................................................................... Georgia .................................................................................................................................... Idaho ........................................................................................................................................ Illinois ....................................................................................................................................... VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00301 ADD-132 Sfmt 4700 Fmt 4701 E:\FR\FM\23OCR3.SGM 1,157 1,173 1,304 907 1,362 852 1,023 1,026 1,198 832 1,456 23OCR3 Final emission goal 1,018 1,031 1,130 828 1,174 786 916 919 1,049 771 1,245 (Page 349 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 136 of 139 64962 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations TABLE 2 TO SUBPART UUUU OF PART 60—STATEWIDE RATE-BASED CO2 EMISSION GOALS—Continued [Pounds of CO2 per net MWh] State Interim emission goal Indiana ..................................................................................................................................... Iowa ......................................................................................................................................... Kansas ..................................................................................................................................... Kentucky .................................................................................................................................. Lands of the Fort Mojave Tribe ............................................................................................... Lands of the Navajo Nation ..................................................................................................... Lands of the Uintah and Ouray Reservation ........................................................................... Louisiana .................................................................................................................................. Maine ....................................................................................................................................... Maryland .................................................................................................................................. Massachusetts ......................................................................................................................... Michigan ................................................................................................................................... Minnesota ................................................................................................................................ Mississippi ................................................................................................................................ Missouri .................................................................................................................................... Montana ................................................................................................................................... Nebraska .................................................................................................................................. Nevada ..................................................................................................................................... New Hampshire ....................................................................................................................... New Jersey .............................................................................................................................. New Mexico ............................................................................................................................. New York ................................................................................................................................. North Carolina .......................................................................................................................... North Dakota ............................................................................................................................ Ohio ......................................................................................................................................... Oklahoma ................................................................................................................................. Oregon ..................................................................................................................................... Pennsylvania ............................................................................................................................ Rhode Island ............................................................................................................................ South Carolina ......................................................................................................................... South Dakota ........................................................................................................................... Tennessee ............................................................................................................................... Texas ....................................................................................................................................... Utah ......................................................................................................................................... Virginia ..................................................................................................................................... Washington .............................................................................................................................. West Virginia ............................................................................................................................ Wisconsin ................................................................................................................................. Wyoming .................................................................................................................................. Final emission goal 1,451 1,505 1,519 1,509 832 1,534 1,534 1,293 842 1,510 902 1,355 1,414 1,061 1,490 1,534 1,522 942 947 885 1,325 1,025 1,311 1,534 1,383 1,223 964 1,258 832 1,338 1,352 1,411 1,188 1,368 1,047 1,111 1,534 1,364 1,526 1,242 1,283 1,293 1,286 771 1,305 1,305 1,121 779 1,287 824 1,169 1,213 945 1,272 1,305 1,296 855 858 812 1,146 918 1,136 1,305 1,190 1,068 871 1,095 771 1,156 1,167 1,211 1,042 1,179 934 983 1,305 1,176 1,299 TABLE 3 TO SUBPART UUUU OF PART 60—STATEWIDE MASS-BASED CO2 EMISSION GOALS [Short tons of CO2] Interim emission goal (2022–2029) tkelley on DSK3SPTVN1PROD with BOOK 2 State Alabama ................................................................................................................................... Arizona ..................................................................................................................................... Arkansas .................................................................................................................................. California .................................................................................................................................. Colorado .................................................................................................................................. Connecticut .............................................................................................................................. Delaware .................................................................................................................................. Florida ...................................................................................................................................... Georgia .................................................................................................................................... Idaho ........................................................................................................................................ Illinois ....................................................................................................................................... Indiana ..................................................................................................................................... Iowa ......................................................................................................................................... Kansas ..................................................................................................................................... Kentucky .................................................................................................................................. Lands of the Fort Mojave Tribe ............................................................................................... Lands of the Navajo Nation ..................................................................................................... Lands of the Uintah and Ouray Reservation ........................................................................... Louisiana .................................................................................................................................. Maine ....................................................................................................................................... Maryland .................................................................................................................................. Massachusetts ......................................................................................................................... Michigan ................................................................................................................................... VerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00302 ADD-133 Sfmt 4700 Fmt 4701 E:\FR\FM\23OCR3.SGM 497,682,304 264,495,976 269,466,064 408,216,600 267,103,064 57,902,920 40,502,952 903,877,832 407,408,672 12,401,136 598,407,008 684,936,520 226,035,288 198,874,664 570,502,416 4,888,824 196,462,344 20,491,560 314,482,512 17,265,472 129,675,168 101,981,416 424,457,200 23OCR3 Final emission goals (2 year blocks starting with 2030–2031) 113,760,948 60,341,500 60,645,264 96,820,240 59,800,794 13,883,046 9,423,650 210,189,408 92,693,692 2,985,712 132,954,314 152,227,670 50,036,272 43,981,652 126,252,242 1,177,038 43,401,174 4,526,862 70,854,046 4,147,884 28,695,256 24,209,494 95,088,128 (Page 350 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 137 of 139 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations 64963 TABLE 3 TO SUBPART UUUU OF PART 60—STATEWIDE MASS-BASED CO2 EMISSION GOALS—Continued [Short tons of CO2] Interim emission goal (2022–2029) State Minnesota ................................................................................................................................ Missouri .................................................................................................................................... Mississippi ................................................................................................................................ Montana ................................................................................................................................... Nebraska .................................................................................................................................. Nevada ..................................................................................................................................... New Hampshire ....................................................................................................................... New Jersey .............................................................................................................................. New Mexico ............................................................................................................................. New York ................................................................................................................................. North Carolina .......................................................................................................................... North Dakota ............................................................................................................................ Ohio ......................................................................................................................................... Oklahoma ................................................................................................................................. Oregon ..................................................................................................................................... Pennsylvania ............................................................................................................................ Rhode Island ............................................................................................................................ South Carolina ......................................................................................................................... South Dakota ........................................................................................................................... Tennessee ............................................................................................................................... Texas ....................................................................................................................................... Utah ......................................................................................................................................... Virginia ..................................................................................................................................... Washington .............................................................................................................................. West Virginia ............................................................................................................................ Wisconsin ................................................................................................................................. Wyoming .................................................................................................................................. 203,468,736 500,555,464 218,706,504 102,330,640 165,292,128 114,752,736 33,947,936 139,411,048 110,524,488 268,762,632 455,888,200 189,062,568 660,212,104 356,882,656 69,145,312 794,646,616 29,259,080 231,756,984 31,591,600 254,278,880 1,664,726,728 212,531,040 236,640,576 93,437,656 464,664,712 250,066,848 286,240,416 Final emission goals (2 year blocks starting with 2030–2031) 45,356,736 110,925,768 50,608,674 22,606,214 36,545,478 27,047,168 7,995,158 33,199,490 24,825,204 62,514,858 102,532,468 41,766,464 147,539,612 80,976,398 16,237,308 179,644,616 7,044,450 51,997,936 7,078,962 56,696,792 379,177,684 47,556,386 54,866,222 21,478,344 102,650,684 55,973,976 63,268,824 TABLE 4 TO SUBPART UUUU OF PART 60— STATEWIDE MASS-BASED CO2 GOALS PLUS NEW SOURCE CO2 EMISSION COMPLEMENT [Short tons of CO2] Interim emission goal (2022–2029) tkelley on DSK3SPTVN1PROD with BOOK 2 State Alabama ................................................................................................................................... Arizona ..................................................................................................................................... Arkansas .................................................................................................................................. California .................................................................................................................................. Colorado .................................................................................................................................. Connecticut .............................................................................................................................. Delaware .................................................................................................................................. Florida ...................................................................................................................................... Georgia .................................................................................................................................... Idaho ........................................................................................................................................ Illinois ....................................................................................................................................... Indiana ..................................................................................................................................... Iowa ......................................................................................................................................... Kansas ..................................................................................................................................... Kentucky .................................................................................................................................. Lands of the Fort Mojave Tribe ............................................................................................... Lands of the Navajo Nation ..................................................................................................... Lands of the Uintah and Ouray Reservation ........................................................................... Louisiana .................................................................................................................................. Maine ....................................................................................................................................... Maryland .................................................................................................................................. Massachusetts ......................................................................................................................... Michigan ................................................................................................................................... Minnesota ................................................................................................................................ Mississippi ................................................................................................................................ Missouri .................................................................................................................................... Montana ................................................................................................................................... Nebraska .................................................................................................................................. Nevada ..................................................................................................................................... New Hampshire ....................................................................................................................... New Jersey .............................................................................................................................. New Mexico ............................................................................................................................. VerDate Sep<11>2014 22:36 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00303 ADD-134 Sfmt 4700 Fmt 4701 E:\FR\FM\23OCR3.SGM 504,534,496 275,895,952 272,756,576 430,988,824 277,022,392 58,986,192 41,133,688 917,904,040 412,826,944 13,155,256 604,953,792 692,451,256 228,426,760 200,960,120 576,522,048 5,186,112 202,938,832 21,167,080 318,356,976 17,592,128 131,042,600 103,782,424 429,446,408 205,761,008 221,990,024 505,904,560 105,704,024 167,021,320 120,916,064 34,519,280 141,919,248 114,741,592 23OCR3 Final emission goals (2 year blocks starting with 2030–2031) 115,272,348 64,760,392 61,371,058 105,647,270 63,645,748 14,121,986 9,562,772 213,283,190 93,888,808 3,278,026 134,398,348 153,885,208 50,563,762 44,441,644 127,580,002 1,292,276 45,911,608 4,788,708 71,708,642 4,219,936 28,996,872 24,606,744 96,188,604 45,862,346 51,332,926 112,105,626 23,913,816 36,926,888 29,436,214 8,121,182 33,752,728 26,459,850 (Page 351 of Total) USCA Case #15-1363 Document #1610010 04/22/2016 Page 138 of 139 64964 Federal Register / Vol. 80, No. 205 / Friday, October Filed: 23, 2015 / Rules and Regulations TABLE 4 TO SUBPART UUUU OF PART 60— STATEWIDE MASS-BASED CO2 GOALS PLUS NEW SOURCE CO2 EMISSION COMPLEMENT—Continued [Short tons of CO2] Interim emission goal (2022–2029) State New York ................................................................................................................................. North Carolina .......................................................................................................................... North Dakota ............................................................................................................................ Ohio ......................................................................................................................................... Oklahoma ................................................................................................................................. Oregon ..................................................................................................................................... Pennsylvania ............................................................................................................................ Rhode Island ............................................................................................................................ South Carolina ......................................................................................................................... South Dakota ........................................................................................................................... Tennessee ............................................................................................................................... Texas ....................................................................................................................................... Utah ......................................................................................................................................... Virginia ..................................................................................................................................... Washington .............................................................................................................................. West Virginia ............................................................................................................................ Wisconsin ................................................................................................................................. Wyoming .................................................................................................................................. 272,940,440 461,424,928 191,025,152 667,812,080 361,531,056 72,774,608 804,705,296 29,819,360 234,516,064 31,963,696 257,149,584 1,707,356,792 220,386,616 240,240,880 97,691,736 469,488,232 252,985,576 295,724,848 Final emission goals (2 year blocks starting with 2030–2031) 63,436,364 103,753,712 42,199,354 149,215,950 82,001,704 17,644,106 181,863,274 7,168,032 52,606,510 7,161,036 57,329,988 396,210,498 50,601,386 55,660,348 23,127,324 103,714,614 56,617,764 66,945,204 [FR Doc. 2015–22842 Filed 10–22–15; 8:45 am] tkelley on DSK3SPTVN1PROD with BOOK 2 BILLING CODE 6560–50–P VerDate Sep<11>2014 22:36 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00304 ADD-135 Sfmt 9990 Fmt 4701 E:\FR\FM\23OCR3.SGM 23OCR3 (Page 352 of Total) USCA Case #15-1363 Document #1610010 Filed: 04/22/2016 Page 139 of 139 CERTIFICATE OF SERVICE I hereby certify that, on this 22nd day of April 2016, a copy of the foregoing final form Addendum Pursuant to Circuit Rule 28(a)(5) to Opening Brief of Petitioners on Core Legal Issues was served electronically through the Court’s CM/ECF system on all ECF-registered counsel. /s/ Elbert Lin Elbert Lin (Page 353 of Total) USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 1 of 67 ORAL ARGUMENT NOT YET SCHEDULED No. 15-1381 (and consolidated cases) ______________________________________ IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT _______________________________________ STATE OF NORTH DAKOTA, et al., V. Petitioners, UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, et al., Respondents. ______________________________________ On Petition for Review of Final Agency Actions of the United States Environmental Protection Agency 80 Fed. Reg. 64,510 (Oct. 23, 2015) and 81 Fed. Reg. 27,442 (May 6, 2016) ______________________________________ STATE PETITIONERS’ OPENING BRIEF ______________________________________ Patrick Morrisey ATTORNEY GENERAL OF WEST VIRGINIA Elbert Lin Solicitor General Counsel of Record Thomas M. Johnson, Jr. Deputy Attorney General Katlyn M. Miller Assistant Attorney General Date: October 13, 2016 Office of the Attorney General State Capitol Building 1, Room 26E Charleston, WV 25305 Tel: (304) 558-2021 Fax: (304) 558-0140 elbert.lin@wvago.gov Counsel for Petitioner State of West Virginia Additional Counsel listed on following pages USCA Case #15-1381 Document #1640985 Luther Strange ATTORNEY GENERAL OF ALABAMA Andrew Brasher Solicitor General Counsel of Record 501 Washington Avenue Montgomery, AL 36130 Tel: (334) 353-2609 abrasher@ago.state.al.us Counsel for Petitioner State of Alabama Filed: 10/13/2016 Page 2 of 67 Mark Brnovich ATTORNEY GENERAL OF ARIZONA John R. Lopez IV Counsel of Record Dominic E. Draye Deputy Solicitor General Keith Miller Assistant Attorney General Maureen Scott Janet Wagner Janice Alward Arizona Corp. Commission, Staff Attorneys 1275 West Washington Phoenix, AZ 85007 Tel: (602) 542-5025 john.lopez@azag.gov dominic.draye@azag.gov keith.miller@azag.gov Counsel for Petitioner Arizona Corporation Commission Leslie Rutledge ATTORNEY GENERAL OF ARKANSAS Lee Rudofsky Solicitor General Counsel of Record Jamie L. Ewing Assistant Attorney General 323 Center Street, Suite 400 Little Rock, AR 72201 Tel: (501) 682-5310 jamie.ewing@arkansasag.gov Counsel for Petitioner State of Arkansas Pamela Jo Bondi ATTORNEY GENERAL OF FLORIDA Jonathan L. Williams Deputy Solicitor General Counsel of Record Jonathan A. Glogau Special Counsel Office of the Attorney General PL-01, The Capitol Tallahassee, FL 32399-1050 Tel: (850) 414-3300 Fax: (850) 410-2672 jonathan.williams@myfloridalegal.com Counsel for Petitioner State of Florida USCA Case #15-1381 Document #1640985 Samuel S. Olens ATTORNEY GENERAL OF GEORGIA Britt C. Grant Solicitor General Counsel of Record 40 Capitol Square S.W. Atlanta, GA 30334 Tel: (404) 656-3300 Fax: (404) 463-9453 bgrant@law.ga.gov Counsel for Petitioner State of Georgia Derek Schmidt ATTORNEY GENERAL OF KANSAS Jeffrey A. Chanay Chief Deputy Attorney General Counsel of Record Bryan C. Clark Assistant Solicitor General 120 S.W. 10th Avenue, 3rd Floor Topeka, KS 66612 Tel: (785) 368-8435 Fax: (785) 291-3767 jeff.chanay@ag.ks.gov bryan.clark@ag.ks.gov Counsel for Petitioner State of Kansas Filed: 10/13/2016 Page 3 of 67 Gregory F. Zoeller ATTORNEY GENERAL OF INDIANA Timothy Junk Deputy Attorney General Counsel of Record Indiana Government Ctr. South Fifth Floor 302 West Washington Street Indianapolis, IN 46205 Tel: (317) 232-6247 tim.junk@atg.in.gov Counsel for Petitioner State of Indiana Andy Beshear ATTORNEY GENERAL OF KENTUCKY Mitchel T. Denham Assistant Deputy Attorney General Joseph A. Newberg, II Assistant Attorney General Counsel of Record 700 Capital Avenue Suite 118 Frankfort, KY 40601 Tel: (502) 696-5611 joe.newberg@ky.gov Counsel for Petitioner Commonwealth of Kentucky USCA Case #15-1381 Document #1640985 Jeff Landry ATTORNEY GENERAL OF LOUISIANA Steven B. “Beaux” Jones Counsel of Record Environmental Section – Civil Division 1885 N. Third Street Baton Rouge, LA 70804 Tel: (225) 326-6085 Fax: (225) 326-6099 jonesst@ag.state.la.us Counsel for Petitioner State of Louisiana Filed: 10/13/2016 Page 4 of 67 Herman Robinson Executive Counsel Donald Trahan Counsel of Record Spencer Bowman Elliott Vega LOUISIANA DEPARTMENT OF ENVIRONMENTAL QUALITY Legal Division P.O. Box 4302 Baton Rouge, LA 70821-4302 Tel: (225) 219-3985 Fax: (225) 219-4068 donald.trahan@la.gov elliott.vega@la.gov Counsel for Petitioner State of Louisiana Department of Environmental Quality Bill Schuette ATTORNEY GENERAL FOR THE PEOPLE OF MICHIGAN Aaron D. Lindstrom Michigan Solicitor General Counsel of Record Neil D. Gordon Assistant Attorney General P.O. Box 30212 Lansing, MI 48909 Tel: (515) 373-1124 Fax: (517) 373-3042 lindstroma@michigan.gov Chris Koster ATTORNEY GENERAL OF MISSOURI James R. Layton Solicitor General Counsel of Record Laura Elsbury Assistant Attorney General P.O. Box 899 207 W. High Street Jefferson City, MO 65102 Tel: (573) 751-1800 Fax: (573) 751-0774 james.layton@ago.mo.gov Counsel for Petitioner People of the State of Michigan Counsel for Petitioner State of Missouri USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 5 of 67 Timothy C. Fox ATTORNEY GENERAL OF MONTANA Alan Joscelyn Chief Deputy Attorney General Dale Schowengerdt Solicitor General Counsel of Record 215 North Sanders Helena, MT 59620-1401 Tel: (406) 444-7008 dales@mt.gov Douglas J. Peterson ATTORNEY GENERAL OF NEBRASKA Dave Bydalek Chief Deputy Attorney General Justin D. Lavene Assistant Attorney General Counsel of Record 2115 State Capitol Lincoln, NE 68509 Tel: (402) 471-2683 justin.lavene@nebraska.gov Counsel for Petitioner State of Montana Counsel for Petitioner State of Nebraska Sam M. Hayes General Counsel Counsel of Record Craig Bromby Deputy General Counsel Andrew Norton Deputy General Counsel NORTH CAROLINA DEPARTMENT OF ENVIRONMENTAL QUALITY 1601 Mail Service Center Raleigh, NC 27699-1601 Tel: (919) 707-8616 sam.hayes@ncdenr.gov Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ohioattorneygeneral.gov Counsel for Petitioner North Carolina Department of Environmental Quality Counsel for Petitioner State of Ohio USCA Case #15-1381 Document #1640985 E. Scott Pruitt ATTORNEY GENERAL OF OKLAHOMA Patrick R. Wyrick Solicitor General P. Clayton Eubanks Deputy Solicitor General Counsel of Record 313 N.E. 21st Street Oklahoma City, OK 73105 Tel: (405) 521-4396 Fax: (405) 522-0669 clayton.eubanks@oag.ok.gov Counsel for Petitioner State of Oklahoma Filed: 10/13/2016 Page 6 of 67 Alan Wilson ATTORNEY GENERAL OF SOUTH CAROLINA Robert D. Cook Solicitor General James Emory Smith, Jr. Deputy Solicitor General Counsel of Record P.O. Box 11549 Columbia, SC 29211 Tel: (803) 734-3680 Fax: (803) 734-3677 esmith@scag.gov Counsel for Petitioner State of South Carolina Marty J. Jackley ATTORNEY GENERAL OF SOUTH DAKOTA Steven R. Blair Assistant Attorney General Counsel of Record 1302 E. Highway 14, Suite 1 Pierre, SD 57501 Tel: (605) 773-3215 steven.blair@state.sd.us Counsel for Petitioner State of South Dakota Ken Paxton ATTORNEY GENERAL OF TEXAS Jeffrey C. Mateer First Assistant Attorney General Scott A. Keller Solicitor General Counsel of Record P.O. Box 12548 Austin, TX 78711-2548 Tel: (512) 936-1700 scott.keller@texasattorneygeneral.gov Counsel for Petitioner State of Texas USCA Case #15-1381 Document #1640985 Sean Reyes ATTORNEY GENERAL OF UTAH Tyler R. Green Solicitor General Counsel of Record Parker Douglas Chief Federal Deputy Utah State Capitol Complex 350 North State Street, Suite 230 Salt Lake City, UT 84114-2320 tylergreen@utah.gov pdouglas@utah.gov Counsel for Petitioner State of Utah Filed: 10/13/2016 Page 7 of 67 Brad Schimel ATTORNEY GENERAL OF WISCONSIN Misha Tseytlin Solicitor General Counsel of Record Andrew Cook Deputy Attorney General Delanie M. Breuer Assistant Deputy Attorney General Wisconsin Department of Justice 17 West Main Street Madison, WI 53707 Tel: (608) 267-9323 tseytlinm@doj.state.wi.us Counsel for Petitioner State of Wisconsin Peter K. Michael ATTORNEY GENERAL OF WYOMING James Kaste Deputy Attorney General Counsel of Record Michael J. McGrady Erik Petersen Senior Assistant Attorneys General Elizabeth Morrisseau Assistant Attorney General 2320 Capitol Avenue Cheyenne, WY 82002 Tel: (307) 777-6946 Fax: (307) 777-3542 james.kaste@wyo.gov Counsel for Petitioner State of Wyoming USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 8 of 67 CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES Pursuant to Circuit Rule 28(a)(1), State Petitioners state as follows: A. Parties, Intervenors, and Amici Curiae These cases involve the following parties: Petitioners: No. 15-1381: State of North Dakota. No. 15-1396: Murray Energy Corporation. No. 15-1397: Energy & Environment Legal Institute. No. 15-1399: State of West Virginia; State of Alabama; State of Arizona Corporation Commission; State of Arkansas; State of Florida; State of Georgia; State of Indiana; State of Kansas; Commonwealth of Kentucky; State of Louisiana; State of Louisiana Department of Environmental Quality; Attorney General Bill Schuette, People of Michigan; State of Missouri; State of Montana; State of Nebraska; The North Carolina Department of Environmental Quality; State of Ohio; State of Oklahoma; State of South Carolina; State of South Dakota; State of Texas; State of Utah; State of Wisconsin; and State of Wyoming. No. 15-1434: International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers & Helpers, AFL-CIO. No. 15-1438: Peabody Energy Corporation. No. 15-1448: Utility Air Regulatory Group and American Public Power Association. i USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 9 of 67 No. 15-1456: National Mining Association. No. 15-1458: Indiana Utility Group. No. 15-1463: United Mine Workers of America, AFL-CIO. No. 15-1468: Alabama Power Company; Georgia Power Company; Gulf Power Company; Mississippi Power Company; and Southern Power Company. No. 15-1469: National Association Chamber of Commerce of the United States of America; of Manufacturers; American Fuel & Petrochemical Manufacturers; National Federation of Independent Business; American Chemistry Council; American Coke and Coal Chemicals Institute; American Foundry Society; American Forest & Paper Association; American Iron and Steel Institute; American Wood Council; Brick Industry Association; Electricity Consumers Resource Council; National Lime Association; National Oilseed Processors Association; and Portland Cement Association. No. 15-1481: American Coalition for Clean Coal Electricity. No. 15-1482: Luminant Generation Company LLC; Oak Grove Management Company LLC; Big Brown Power Company LLC; Sandow Power Company LLC; Big Brown Lignite Company LLC; Luminant Mining Company LLC; and Luminant Big Brown Mining Company LLC. No. 15-1484: National Rural Electric Cooperative Association; Basin Electric Power Cooperative; East Kentucky Power Cooperative, Inc.; Hoosier Energy Rural Electric Cooperative, Inc.; Minnkota Power Cooperative, Inc.; Sunflower ii USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 10 of 67 Electric Power Corporation; and Tri-State Generation and Transmission Association, Inc. No. 16-1218: Murray Energy Corporation. No. 16-1220: State of West Virginia; State of Alabama; State of Arizona Corporation Commission; State of Arkansas; State of Florida; State of Georgia; State of Indiana; State of Kansas; Commonwealth of Kentucky; State of Louisiana; State of Louisiana Department of Environmental Quality; Attorney General Bill Schuette, People of Michigan; State of Missouri; State of Montana; State of Nebraska; The North Carolina Department of Environmental Quality; State of Ohio; State of Oklahoma; State of South Carolina; State of South Dakota; State of Texas; State of Utah; State of Wisconsin; and State of Wyoming. No. 16-1221: Utility Air Regulatory Group and American Public Power Association. No. 16-1227: Energy & Environment Legal Institute. Respondents: Respondents are the United States Environmental Protection Agency (in Nos. 15-1381, 15-1397, 15-1434, 15-1448, 15-1456, 15-1463, 15-1481, 15-1484, 16-1221, 16-1227) and the United States Environmental Protection Agency and Gina McCarthy, Administrator (in Nos. 15-1396, 15-1399, 15-1438, 15-1458, 15-1468, 151469, 15-1480, 15-1482, 16-1218, 16-1220). iii USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 11 of 67 Intervenors and Amici Curiae: Lignite Energy Council and Gulf Coast Lignite Coalition are PetitionerIntervenors. American Lung Association; Center for Biological Diversity; Clean Air Council; Clean Wisconsin; Conservation Law Foundation; Environmental Defense Fund; Natural Resources Defense Council; Ohio Environmental Council; Sierra Club; State of California by and through Governor Edmund G. Brown, Jr., and the California Air Resources Board, and Attorney General Kamala D. Harris; State of Connecticut; State of Delaware; State of Hawaii; State of Illinois; State of Iowa; State of Maine; State of Maryland; State of Minnesota by and through the Minnesota Pollution Control Agency; State of New Hampshire; State of New Mexico; State of New York; State of Oregon; State of Rhode Island; State of Vermont; State of Washington; Commonwealth of Massachusetts; Commonwealth of Virginia; District of Columbia; City of New York; Golden Spread Electric Cooperative, Inc.; NextEra Energy, Inc.; Calpine Corporation; The City of Austin d/b/a Austin Energy; The City of Los Angeles, by and through its Department of Water and Power; The City of Seattle, by and through its City Light Department; National Grid Generation, LLC; New York Power Authority; Pacific Gas and Electric Company; Sacramento Municipal Utility District; Tri-State Generation and Transmission Association, Inc. are RespondentIntervenors. There are no amici curiae in these consolidated cases. iv USCA Case #15-1381 B. Document #1640985 Filed: 10/13/2016 Page 12 of 67 Rulings Under Review These consolidated cases involve final agency action of the United States Environmental Protection Agency entitled, “Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units,” published on October 23, 2015, at 80 Fed. Reg. 64,510, and “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units,” published on May 6, 2016, at 81 Fed. Reg. 27,442. C. Related Cases These consolidated cases have not previously been before this Court or any other court. Per the Court’s order of March 24, 2016, the following case was severed and is being held in abeyance pending potential administrative resolution of biogenic carbon dioxide emissions issues in the Final Rule: Biogenic CO2 Coalition v. EPA, No. 15-1480. v USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 13 of 67 TABLE OF CONTENTS Page CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES ................. i TABLE OF CONTENTS ................................................................................................... vi TABLE OF AUTHORITIES ........................................................................................... viii GLOSSARY ......................................................................................................................... xiii JURISDICTIONAL STATEMENT ................................................................................... 1 STATEMENT OF ISSUES ................................................................................................. 1 STATUTES AND REGULATIONS ................................................................................. 2 INTRODUCTION................................................................................................................ 2 STATEMENT OF THE CASE .......................................................................................... 5 I. Section 111 Of The CAA........................................................................................... 5 II. The President’s Climate Action Plan ........................................................................ 5 A. The Rule ........................................................................................................... 6 B. The Power Plan Rule ...................................................................................... 8 SUMMARY OF ARGUMENT ........................................................................................... 9 STANDING ......................................................................................................................... 11 STANDARD OF REVIEW ............................................................................................... 12 ARGUMENT ....................................................................................................................... 13 I. EPA Failed To Apply The Correct Legal Standard When Concluding That Its BSER Was Adequately Demonstrated. ................................................... 13 A. Adequate Demonstration Requires Full Commercial-Scale Operation Of The Entire Integrated System. ............................................ 13 B. EPA’s Attempts To Change The “Adequate Demonstration” Standard Are Unlawful. ................................................................................ 16 C. To The Extent That There Is Any Ambiguity As To EPA’s Burden, The CAA And EPAct Should Be Interpreted To Prevent EPA From Intruding On The States’ Traditional Authority Over vi USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 14 of 67 Energy Production. ....................................................................................... 23 II. III. IV. EPA Failed To Show In The Record That Its BSER Is Adequately Demonstrated. ........................................................................................................... 25 A. The Record Does Not Contain Any Evidence Of FullyIntegrated, Commercial-Scale Operations.................................................. 25 B. EPA Fails To Meet Even Its Incorrect, Reduced Legal Standard. ......... 27 EPA Failed To Adequately Consider And Weigh The Benefits And Costs Of The Rule. .............................................................................................................. 29 A. EPA Has A Statutory Obligation To Consider And Weigh Costs And Benefits Under The CAA. ................................................................... 29 B. The Rule Should Be Vacated Because EPA Admits That The Rule Is Not Projected To Yield Any Benefits. ................................................... 31 C. The Rule Should Be Vacated Because EPA’s BSER Is Exorbitantly Costly And Therefore Has Not Been Adequately Demonstrated. ............................................................................................... 32 EPA Failed To Make The Statutorily-Required Endangerment And Significant Contribution Findings. .......................................................................... 34 CONCLUSION ................................................................................................................... 37 vii USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 15 of 67 TABLE OF AUTHORITIES Cases Airmark Corp. v. FAA, 758 F.2d 685 (D.C. Cir. 1985) ........................................................................................ 34 Am. Equity Inv. Life Ins. Co. v. SEC, 613 F.3d 166 (D.C. Cir. 2009) .................................................................................. 31, 32 Ark. Elec. Coop. Corp. v. Ark. Pub. Serv. Comm'n, 461 U.S. 375 (1983).......................................................................................................... 24 Bond v. United States, 134 S. Ct. 2077 (2014) ..................................................................................................... 23 Bus. Roundtable v. SEC, 647 F.3d 1144 (D.C. Cir. 2011) ................................................................................ 31, 32 Chevron, U.S.A., Inc. v. Natural Res. Def. Council, 467 U.S. 837 (1984).......................................................................................................... 21 Coal. for Responsible Regulation, 684 F.3d 102 (D.C. Cir. 2012) .................................................................................. 36, 37 *Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973) ............................................................... 15, 17, 26, 30, 32 Ethyl Corp. v. EPA, 541 F.2d 1 (D.C. Cir. 1976) ...................................................................................... 21, 22 viii USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 16 of 67 FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120 (2000).......................................................................................................... 23 Heller v. Doe, 509 U.S. 312 (1993).......................................................................................................... 36 King v. Burwell, 135 S. Ct. 2480 (2015) ............................................................................................... 23, 35 Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999) .................................................................................. 19, 30 Massachusetts v. EPA, 549 U.S. 497 (2007).......................................................................................................... 37 Merrill Lynch, Pierce, Fenner & Smith, Inc. v. Curran, 456 U.S. 353 (1982).......................................................................................................... 15 Michigan v. EPA, 135 S. Ct. 2699 (2015) ............................................................................................... 10, 30 Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29 (1983) ...................................................................................................... 27, 34 Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980) .................................................................................. 12, 16 Nken v. Holder, 556 U.S. 418 (2009)............................................................................................................ 9 ix USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 17 of 67 Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461 U.S. 190 (1983).................................................................................................... 12, 24 *Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973) .............................................. 9, 13, 14, 17, 18, 19, 30, 34 Portland Cement Ass'n v. Train, 513 F.2d 506 (D.C. Cir. 1975) ........................................................................................ 30 Price Waterhouse v. Hopkins, 490 U.S. 228 (1989) .......................................................................................................... 22 Raygor v. Regents of Univ. of Minn., 534 U.S. 533 (2002).......................................................................................................... 24 Severino v. N. Fort Myers Fire Control Dist., 935 F.2d 1179 (11th Cir. 1991)....................................................................................... 22 *Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) .................................................... 9, 14, 15, 17, 18, 26, 28 SW General, Inc. v. Nat'l Labor Relations Bd., 796 F.3d 67 (D.C. Cir. 2015) .......................................................................................... 21 West Virginia v. EPA, 362 F.3d 861 (D.C. Cir. 2004) ........................................................................................ 12 x USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 18 of 67 Statutes 26 U.S.C. § 48A(g) ....................................................................................................10, 20, 21 29 U.S.C. § 794(a) ................................................................................................................. 22 *42 U.S.C. § 7411(a) ............................................................................................ 5, 13, 19, 30 *42 U.S.C. § 7411(b)...................................................................................... 1, 25, 11, 34, 35 42 U.S.C. § 7411(j) ................................................................................................................ 15 42 U.S.C. § 7601(a) ......................................................................................................... 30, 31 42 U.S.C. § 7607(b)................................................................................................................. 1 42 U.S.C. § 7607(d)............................................................................................................... 12 42 U.S.C. § 13573(e) ............................................................................................................. 20 42 U.S.C. § 13574(d) ............................................................................................................ 20 42 U.S.C. § 15962(a) ............................................................................................................. 16 42 U.S.C. § 15962(i)........................................................................................................ 16, 20 Pub. L. No. 109-58, 119 Stat. 594 (2005) ............................................................................ 7 Regulations 40 C.F.R. Part 60, Subpart TTTT and Parts 70, 71, and 98 .............................................. 2 77 Fed. Reg. 22,391 (Apr. 13, 2012) ................................................................................... 33 79 Fed. Reg. 1,430 (Jan. 8, 2014) .................................................................................... 7, 18 79 Fed. Reg. 10,750 (Feb. 26, 2014) ............................................................................... 8, 25 xi USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 19 of 67 *80 Fed. Reg. 64,510 (Oct. 23, 2015) .... 1, 6, 8-9, 16, 19-20, 22-23, 25, 26, 28-29, 31-32, 35, 36 80 Fed. Reg. 64,600 (Dec. 22, 2015) ................................................................. 8, 11, 17, 19 81 Fed. Reg. 27,442 (May 6, 2016) ....................................................................................... 1 _____________________________ * Authorities upon which we chiefly rely are marked with asterisks. xii USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 20 of 67 GLOSSARY BSER Best System of Emission Reduction CAA Clean Air Act CCS Carbon Capture and Storage DOE Department of Energy EGU Electric Generating Unit EPAct Energy Policy Act of 2005 EPAct TSD Technical Support Document-Effect of EPAct05 on BSER for New Fossil Fuel-fired Boilers and IGCCs SCPC Supercritical Pulverized Coal xiii USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 21 of 67 JURISDICTIONAL STATEMENT Petitioners seek review of U.S. Environmental Protection Agency (“EPA”) final agency actions entitled “Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units,” 80 Fed. Reg. 64,510 (Oct. 23, 2015), Joint Appendix (“JA”) ___-___ (the “Rule”), and “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units,” 81 Fed. Reg. 27,442 (May 6, 2016). Petitions for review were timely filed in this Court under section 307(b)(1) of the Clean Air Act (the “CAA”), 42 U.S.C. § 7607(b)(1). STATEMENT OF ISSUES 1. Whether EPA failed to apply the correct legal standard when determining whether its “best system of emission reduction” had been “adequately demonstrated” under CAA section 111(b), 42 U.S.C. § 7411(b), namely, whether the entire selected “system” is commercially available at full-scale facilities; 2. Whether EPA exceeded its authority under the CAA because, regardless of the legal standard applied, it failed to meet its burden of showing that efficient new supercritical pulverized coal (“SCPC”) utility boilers implementing partial carbon capture and storage (“CCS”) in deep saline formations is in fact the “best system of emission reduction” for CO2 at fossil-fuel-fired steam generating units; 1 USCA Case #15-1381 3. Document #1640985 Filed: 10/13/2016 Page 22 of 67 Whether EPA exceeded its authority under the CAA in selecting its “best system of emission reduction” by failing to adequately consider the costs and benefits of the Rule; and 4. Whether EPA failed to properly consider whether CO2 emissions are “reasonably ... anticipated to endanger public health or welfare,” and whether fossilfuel-fired steam generating units “contribute[] significantly” to that endangerment, as required for EPA to regulate under the CAA § 111(b), 42 U.S.C. § 7411(b). STATUTES AND REGULATIONS The Rule is codified in 40 C.F.R. Part 60, Subpart TTTT and Parts 70, 71, and 98. The Statutory and Regulatory Addendum reproduces pertinent portions of cited statutes and regulations. INTRODUCTION This Rule is a cornerstone of EPA’s agenda to eliminate coal-fired power plants from the mix of energy generation relied on by States. It is designed—by virtue of an impossibly high technology standard—to eliminate the construction of new coal-fired power plants. It is also a statutory predicate for the 111(d) Rule (“Power Plan Rule”), which is EPA’s tool to eliminate existing coal-fired power plants. But like the Power Plan Rule, which has been separately challenged before this Court, this Rule far exceeds the agency’s authority. Congress has not granted EPA the power to choose winners and losers in the energy marketplace. Indeed, even the Federal Energy Regulatory Commission is prohibited under the Federal Power Act 2 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 23 of 67 from exercising such authority. The CAA grants EPA the authority to regulate air pollution, but specifically requires that EPA’s standards reflect “demonstrated” levels of technology that are also cost-effective, precisely so that pollution regulation does not become a cudgel for EPA to force unwanted industries out of business. Among many deficiencies, the Rule fails to satisfy the statutory requirement that EPA select a “best system of emission reduction” (“BSER”) that has been “adequately demonstrated.” Under this Court’s case law, EPA must show that the entire selected system is commercially available for implementation at new, full-scale facilities. As counsel for EPA recently conceded to this Court, sitting en banc to hear challenges to the Power Plan Rule, “the statute directly requires that any system of emission reduction be adequately demonstrated,” which means that “any emission reduction system that isn’t already in place and successful within an industry can’t be used ....” Transcript of Oral Argument, State of West Virginia v. EPA, No. 15-1363, 61 (emphasis added). Relatedly, EPA is prohibited under the Energy Policy Act of 2005 (“EPAct”) from considering facilities that receive certain federal subsidies or tax credits when determining whether a system has been “adequately demonstrated”—for the very reason that subsidized, emergent technologies have not proven to be commercially viable. But instead of attempting to show that its BSER is a demonstrated, commercially available technology, EPA employs various sleights of hand to attempt 3 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 24 of 67 to reduce its statutory burden. First, it erroneously asserts that it need only show that its BSER is “technically feasible,” rather than commercially available. Second, EPA claims that it need not demonstrate the operation of its “system” as an integrated whole, but need only show the feasibility of each component part of the system. Third, EPA relies on a plainly erroneous interpretation of EPAct to conclude that it may consider covered, subsidized facilities to support its adequate demonstration analysis so long as it also considers even a scintilla of other evidence. EPA cannot cobble together various component technologies that exist only in highly-subsidized, pilot-scale, or experimental form and declare the amalgam “adequately demonstrated.” Much like the griffin, which combines parts of the bodies of different animals into one mythical creature, EPA’s BSER does not exist in the integrated form mandated by the agency anywhere in the world, and the closest analogues are either small-scale plants or plants that receive significant government funding. EPA’s purpose behind imposing its unproven BSER on regulated plants is clear—to ensure that coal-fired energy has no future in the energy landscape. But EPA cannot set unachievable national emissions standards for new fossil-fuel-fired steam generating units to transform the energy economy in this manner. The Rule is not a faithful application of section 111 and must be vacated. 4 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 25 of 67 STATEMENT OF THE CASE I. Section 111 Of The CAA Enacted in 1970 and amended in 1977 and 1990, CAA section 111 authorizes EPA to impose nationwide emission limits—a “standard of performance”—on any category of new and modified stationary sources that the agency has found “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” 42 U.S.C. § 7411(b)(1)(A). CAA section 111(a)(1) defines “standard of performance” to include several important statutory limitations on EPA’s power to set emission standards on stationary sources. A “standard of performance” means: a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. 42 U.S.C. § 7411(a)(1). II. The President’s Climate Action Plan After Congress repeatedly rejected legislation authorizing greenhouse gas reduction programs, President Obama ordered EPA to use CAA section 111 to force steam generating units to make steep reductions in CO2 emissions. See Power Sector Carbon Pollution Standards: Memorandum for the Administrator of the Environmental Protection Agency, 78 Fed. Reg. 39,535 (June 25, 2013), JA___-___. On October 23, 2015, EPA 5 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 26 of 67 did as directed, simultaneously adopting two major rules under CAA section 111(b) and section 111(d), regulating CO2 emissions from new, modified, reconstructed, and existing fossil-fuel-fired steam generating units, respectively. See 80 Fed. Reg. 64,510 (Oct. 23, 2015), JA___-___; Id. at 64,662 (Oct. 23, 2015), JA___-___. A. The Rule The Rule requires, among other things, that new fossil-fuel-fired steam generating units limit CO2 emissions to 1,400 lb. CO2/MWh-g.1 To justify this standard, EPA selected as the BSER “a new highly efficient SCPC [electric generating unit (‘EGU’)] implementing partial post-combustion CCS”, 80 Fed. Reg. at 64,542, JA___, in “deep saline formations,” id. at 64,579 (“the determination that the BSER is adequately demonstrated ... relies on [geologic sequestration] in deep saline formations”), JA___. EPA claims that new units can achieve this standard by implementing a SCPC unit that captures CO2 post-combustion. Id. at 64,513, JA___. EPA concedes in the Rule that even the most efficient, commercially-available new fossil-fuel-fired steam generating units will be unable to meet a 1,400 lb. CO2/MWh-g standard in the absence of CCS. Id. at 64,548, JA___. EPA also notes that Integrated Gasification Combined Cycle technology—though not part of its BSER—can either 1 The Rule also establishes a standard for reconstructed and modified steam generating units. 80 Fed. Reg. at 64,512, JA___. State Petitioners focus here on the requirements for new sources, but agree with Non-State Petitioners that the modified and reconstructed standards are unlawful. Non-State Br. III. 6 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 27 of 67 implement CCS or natural gas co-firing as an alternative method of compliance with the Rule. Id. at 64,514, JA___. In the preamble to the Rule, EPA acknowledges that it must show that its BSER is “adequately demonstrated.” Id. at 64,512, JA___. But contrary to case law, EPA concludes that, to satisfy this standard, it need only show that its proposed system is “technically feasible.” See, e.g., id. at 64,513, 64,527, 64,538, JA___, ___, ___. EPA reasoned that “[t]here is no requirement, as part of the BSER determination, that the EPA finds that the technology in question is ‘commercially available.’” Id. at 64,556, JA___. EPA also rejected the conclusion that it must show that a BSER’s component parts can operate as a fully-integrated system. Id. EPA instead construed the CAA as allowing it to “legitimately infer that a technology is demonstrated as a whole based on operation of component parts which have not, as yet, been fully integrated.” Id. EPA also relied on a host of federally-subsidized facilities in support of its analysis that its BSER had been adequately demonstrated. Id. at 64,548, 64,551-55, JA___, ___-___. While EPA did not address EPAct when it proposed the Rule, see 79 Fed. Reg. 1,430 (Jan. 8, 2014), JA___, that statute has prohibited the agency since 2005 from even “consider[ing]” technology as adequately demonstrated under CAA section 111 where the technology is used at a facility receiving certain federal subsidies or tax credits. See Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005). But rather than withdraw the Rule, as State Petitioners requested in comments, 7 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 28 of 67 Comments of West Virginia, et al., EPA-HQ-OAR-2013-0495-9505, at 8 (May 9, 2014) (“West Virginia Comments”) (requesting that EPA withdraw its proposal because it violated EPAct on its face), JA___, EPA issued a separate request for comment on the effect of EPAct, 79 Fed. Reg. 10,750 (Feb. 26, 2014), JA___. And in the final Rule, EPA construed the limitations of EPAct narrowly, concluding that EPAct “preclude[s] [it] from relying solely on the experience of facilities that received [Department of Energy (“DOE”)] assistance, but [does] not [] preclude [it] from relying on the experience of such facilities in conjunction with other information.” 80 Fed. Reg. at 64,541, JA___. Despite imposition of this novel BSER on regulated entities, EPA concluded that any costs and benefits associated with the Rule would be negligible because “existing and anticipated economic conditions are such that few, if any, fossil-fuelfired steam-generating EGUs will be built in the foreseeable future.” Id. at 64,515, JA___. EPA thus concluded that the Rule would not produce “notable CO2 emission changes, energy impacts, monetized benefits, costs, or economic impacts.” Id. at 64,642, JA___. B. The Power Plan Rule Having established a section 111(b) rule, EPA then invoked section 111(d) to promulgate its Power Plan Rule, which unlawfully set binding emission limitations that require sharp CO2 reductions for existing fossil-fuel-fired steam generating units. 80 Fed. Reg. at 64,662, JA___. 8 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 29 of 67 State Petitioners challenged the Power Plan Rule in a separate proceeding before this Court and sought a stay pending judicial review. See West Virginia v. EPA, No. 15-1363 (and consolidated cases) (D.C. Cir. filed Oct. 23, 2015). On February 9, 2016, the Supreme Court stayed the Power Plan, halting its enforceability and its deadlines pending Supreme Court review. Order in Pending Case, West Virginia v. EPA, No. 15A773 (U.S. Feb. 9, 2016); see Nken v. Holder, 556 U.S. 418, 428 (2009). SUMMARY OF ARGUMENT I. In adopting the Rule, EPA far exceeded the authority provided by Congress under section 111(b) of the CAA to set emission standards for new fossil-fuel-fired steam generating units. The CAA requires a rigorous showing that the selected “best system of emission reduction” be “adequately demonstrated.” The text and structure of the CAA, and its consistent interpretation by this Court, make clear that EPA must demonstrate that its preferred “system” is commercially available. Sierra Club v. Costle, 657 F.2d 298, 319 (D.C. Cir. 1981); Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973). Rather than hold itself to this well-established standard, EPA has impermissibly “relaxed” its statutory burden. Costle, 657 F.2d at 341 n.157. The agency claims that it need only show that the individual component parts of its selected system are “technically feasible.” 80 Fed. Reg. at 64,513, JA___. Worse, EPA’s reliance on facilities that receive government funding violates Congress’s explicit instruction in 9 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 30 of 67 EPAct that such facilities shall not be “considered” in determining whether a particular system has been “adequately demonstrated.” 26 U.S.C. § 48A(g). If permitted to stand, EPA’s interpretation would eliminate an important check on the agency’s authority under section 111(b). If EPA can require emission reductions based on a system that does not exist at commercial scale anywhere in the world, it has the power to deter the construction of new coal-fired plants in favor of EPA’s preferred energy sources. That is inconsistent with the statutory text and this Court’s cases. And at a minimum, it is a direct intrusion on the States’ traditional authority over electricity generation that requires a clear statement from Congress. II. Applying the correct legal standard here, there can be no doubt that EPA’s BSER has not been adequately demonstrated. Without small-scale pilot programs and facilities that have received federal funding under EPAct, EPA can only identify one facility where it claims its BSER is fully operational—Canada’s Boundary Dam. But that facility receives substantial government funding, like the EPAct facilities. It is also less than one-quarter the size of a full-scale power plant, has suffered massive cost overruns, and does not sequester in deep saline formations. It is not sufficient to carry EPA’s burden to show adequate demonstration. III. EPA has also failed to adequately consider the costs and benefits of the new Rule, as required by the CAA. The Supreme Court and this Court have required that EPA engage in a reasoned analysis of costs before engaging in significant rulemaking. See Michigan v. EPA, 135 S. Ct. 2699, 2706 (2015); infra III.A. Here, EPA 10 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 31 of 67 ignored the significant costs that imposing a nationwide CCS-based standard would have in deterring the creation of new plants. And EPA adopted the Rule despite admitting that it would result in negligible CO2 savings. It violates the CAA for EPA to adopt a costly Rule while conceding that the Rule is unlikely to result in any discernible benefit. IV. Finally, EPA bypassed critical statutory conditions that it must satisfy before it can even consider the specifics of any 111(b) rule. Specifically, Congress required that EPA find that the air pollutant it seeks to regulate “may reasonably be anticipated to endanger public health or welfare,” and that the source category to be regulated actually “contributes significantly” to that endangerment. 42 U.S.C. § 7411(b)(1)(A). Yet EPA failed to comply with these straightforward prerequisites in promulgating the Rule. It erred in concluding that the source category here had already been listed, and even assuming the source category had been listed, EPA was wrong in asserting that it only needs a “rational basis” to regulate a new pollutant from a previously-listed source category. STANDING State Petitioners have standing because the Rule is a necessary legal predicate for EPA’s Power Plan Rule, which requires States to create and submit state plans to implement EPA’s CO2 emission limits. 80 Fed. Reg. at 64,669, JA___. The Rule is a but-for cause of the States’ obligation to revise or create a section 111(d) state plan, 11 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 32 of 67 which is an injury-in-fact sufficient for standing. West Virginia v. EPA, 362 F.3d 861, 868 (D.C. Cir. 2004). State Petitioners also have standing because the Rule mandates a BSER that is not commercially available, which will deter the construction of new coal-fired steam generating units within the States. This intrudes on the States’ “traditional authority over the need for additional generating capacity, the type of generating facilities to be licensed, land use, ratemaking, and the like.” Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. Comm’n, 461 U.S. 190, 212 (1983). STANDARD OF REVIEW This Court’s decisions “have established a rigorous standard of review under section 111.” Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 429 (D.C. Cir. 1980). “EPA must affirmatively show” during the rulemaking process that its BSER is adequately demonstrated. See id. at 433. This Court must set aside final EPA action that is “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law;” “contrary to constitutional right, power, privilege, or immunity;” or “in excess of statutory jurisdiction, authority, or limitations, or short of statutory right.” 42 U.S.C. § 7607(d)(9)(A)–(C). 12 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 33 of 67 ARGUMENT I. EPA Failed To Apply The Correct Legal Standard When Concluding That Its BSER Was Adequately Demonstrated. In the Rule, EPA concocts a new legal standard that impermissibly and significantly reduces its statutory burden. As noted, section 111 requires that a standard of performance “reflect[] the degree of emission limitation achievable through the application of the [BSER] which ... has been adequately demonstrated.” Id. § 7411(a)(1). But EPA concluded that it only needed to show that each individual component of its BSER was “technically feasible.” This new standard conflicts with the text, history, and structure of the CAA and this Court’s longstanding interpretation of section 111(b). As further explained in Part B, EPA’s flawed legal analysis renders most of EPA’s supporting evidence inadmissible, and what little evidence remains is insufficient to show that its BSER is adequately demonstrated. A. Adequate Demonstration Requires Full Commercial-Scale Operation Of The Entire Integrated System. Contrary to EPA’s assertion, the CAA’s “adequate demonstration” standard requires EPA to show commercial availability. As this Court has explained, this standard first appeared prior to enactment of the original 1970 CAA in Conference Committee, which rejected earlier versions proposed by both the House and Senate. Portland Cement, 486 F.2d at 391. The House had initially proposed a standard similar to what EPA advocates here, namely, that EPA give “‘appropriate consideration to 13 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 34 of 67 technological and economic feasibility.’” Id. (emphases added). But that did not become law. In parsing the legislative history of the “adequate demonstration” requirement, this Court identified the “essential question” as “whether the technology would be available for installation in new plants.” Id. Thus, under the “final language adopted, … it must be ‘adequately demonstrated’ that there will be ‘available technology.’” Id. In decisions following the CAA’s enactment, this Court confirmed and elaborated on the commercial availability requirement. Notably, in American Petroleum Institute v. EPA, this Court rejected the EPA’s reliance on “‘pilot plant data’” to demonstrate the effectiveness of carbon adsorption technology, which the EPA conceded “‘needs further development before [the technology] will show the high degree of effectiveness in large-scale operation that it has already shown in pilot plant demonstrations.’” 540 F.2d 1023, 1038 (D.C. Cir. 1976). Similarly, in Costle, this Court noted a distinction between an “innovative or emerging technology” and an “adequately demonstrated” system. Costle, 657 F.2d at 341 n.157. In that case, the record indicated that dry scrubbing was not an “adequately demonstrated” technology because the record reflected that “‘crucial issues such as waste disposal and demonstration of commercial-scale systems, which may continue to limit the overall acceptability of this technology, remain to be answered.’” Id. (internal citation omitted). There, EPA conceded that there were “‘no full scale dry scrubbers ... presently in operation,’” and relied instead on pilot scale test data. Id. 14 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 35 of 67 (internal citation omitted). But this Court concluded that this evidence provided “no basis” to conclude “that dry scrubbing is adequately demonstrated for full scale plants throughout this industry.” Id.2 The distinction drawn in Costle finds additional support in section 111(j) of the CAA, which specifically refers to an “innovative technological system” as one which has “not been adequately demonstrated.” 42 U.S.C. § 7411(j) (emphasis added). New sources may employ such systems only if they show that use of the “innovative” system would achieve a “greater” degree of emission reduction and if they can demonstrate that the system “will not cause or contribute to an unreasonable risk to public health, welfare, or safety in its operation, function, or malfunction.” Id. Because such vanguard technologies would not be in ordinary commercial use, and would therefore be untested, Congress required additional safeguards before new sources could adopt them. Furthermore, Congress is “presumed to be aware of an administrative or judicial interpretation of a statute and to adopt that interpretation when it re-enacts a statute without change.” Merrill Lynch, Pierce, Fenner & Smith, Inc. v. Curran, 456 U.S. 2 In those instances when this Court has permitted EPA to rely in part on pilot-scale data, it is only because EPA has proven that such data is “representative of full-scale performance.” Id. at 382. And EPA has typically supplemented this data with further evidence of full-scale commercial use. See, e.g., id. at 380 (record for achievability of standard for baghouse technology included “limited data from one full scale commercial sized operation,” among other evidence); Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 1973) (record included “tests of prototype and full-scale control systems,” among other evidence). 15 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 36 of 67 353, 382 n.66 (1982). Here, Congress amended the CAA in 1977 and 1990, but on neither occasion changed the “adequately demonstrated” standard. Indeed, if anything, Congress reinforced the commercial availability test when it enacted EPAct in 2005. That statute instructed EPA that no facility that received certain forms of government funding “shall be considered to be ... adequately demonstrated.” 42 U.S.C. § 15962(i). Congress explained that those projects “advance efficiency, environmental performance, and cost competitiveness well beyond the level of technologies that are in commercial service or have been demonstrated on a scale” that DOE “determine[s] is sufficient to demonstrate that commercial service is viable as of [the date of enactment].” 42 U.S.C. § 15962(a) (emphasis added). The statute is clear: If a facility requires subsidies to exist, it is unlikely to be commercially viable at the present time, and therefore, is not “adequately demonstrated.” B. EPA’s Attempts To Change The “Adequate Demonstration” Standard Are Unlawful. EPA attempts to lighten its burden to “affirmatively show” that its BSER is adequately demonstrated. See Nat’l Lime Ass’n, 627 F.2d at 433. But none of its maneuvers are permitted under the CAA. 1. The Adequate Demonstration Analysis Requires More Than Showing That The System Is Merely Technically Feasible. First, EPA improperly attempts to replace the adequately demonstrated standard with a completely novel “technical feasibility” standard. See, e.g., 80 Fed. Reg. at 64,513, JA___. As noted above, Congress specifically considered and rejected a 16 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 37 of 67 “technological ... feasibility” standard in drafting the CAA. And unsurprisingly, no federal case interpreting section 111 uses the phrases “technically feasible” or “technical feasibility” in the context of adequate demonstration of its BSER. To be sure, this Court has discussed whether the system EPA selected had the “technological feasibility” “to achieve mandated pollution control.” Portland Cement, 486 F.2d at 388 (examining both adequate demonstration and achievability); see also Costle, 657 F.2d at 318-19. But these discussions deal with the separate statutory requirement that the emission limits set by EPA be “achievable” by the source. See Essex, 486 F.2d at 433. That is, assuming EPA has shown that its BSER is adequately demonstrated, EPA must also show that its selected BSER has the ability to “achiev[e]” the selected “standard for emissions of air pollutants” set by EPA, id. at 433.3 That independent limitation on EPA’s authority must not be conflated with the prior, foundational inquiry that the selected BSER be “available for installation in new plants.” Portland Cement, 486 F.2d at 391. EPA ignores that requirement here. EPA suggests that the CAA permits it to adopt unproven systems under the guise of “promot[ing] technological development.” See 80 Fed. Reg. at 64,600, JA___. That too is incorrect. While this Court has acknowledged that “Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants,” this Court noted 3 For other, independently sufficient reasons, EPA has failed to show that its BSER can “achieve” the standard. See Non-State Br. I.C. & III.B. 17 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 38 of 67 in the same breath that “[t]he essential question [i]s ... whether the technology [is] available for installation in new plants.” Portland Cement, 486 F.2d at 391; Costle, 657 F.2d at 364 n.276 (quoting Portland Cement). Therefore, while EPA need not select a technology that represents the current industry standard, it must select a technology that currently exists and is commercially viable. It has failed to do so here. 2. The Adequate Demonstration Analysis Requires SystemWide Demonstration, Not Demonstration of Individual Components. EPA also impermissibly attempts to undermine the CAA by applying its invented “technical feasibility” standard not to the CCS system as a whole, but to each of its “components,” asserting that it is “[un]necessary that the major components be demonstrated in an integrated process in order to determine the technical feasibility of each component.” See EPA, Docket EPA-HQ-OAR-2013-0495, Technical Support Document-Effect of EPAct05 on BSER for New Fossil Fuel-fired Boilers and IGCCs (2014) at 4, https://www.epa.gov/sites/production/files/2014-01/documents/ 2013_proposed_cps_for_new_power_plants_tsd.pdf (“EPAct TSD”), JA___; see also 79 Fed. Reg. 1471, JA___. EPA’s component approach, however, conflicts with EPA’s own understanding of the word “system.” As EPA argued in the preamble to the Power Plan Rule, the “ordinary, everyday meaning of ‘system’” includes “a set of things or parts forming a complex whole;” “a group of interacting, interrelated, or interdependent elements;” and “an assemblage or combination of things or parts 18 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 39 of 67 forming a complex or unitary whole.”4 80 Fed. Reg. at 64,720 & n.314 (collecting dictionaries), JA___. These definitions, coupled with the statutory text, confirm that EPA must show that the entire, integrated “system ... has been adequately demonstrated.” 42 U.S.C. § 7411(a)(1) (emphasis added). This conclusion comports with this Court’s precedents instructing that “EPA may not base its determination that a technology is adequately demonstrated ... on mere speculation or conjecture.” Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. Cir. 1999). By purporting to show merely that components of a system are technically feasible without proving that they can be successfully integrated in a fullscale commercial plant, EPA impermissibly relies on “‘crystal-ball’ inquiry” to attempt to demonstrate its system. Portland Cement, 486 F.2d at 391. 3. EPA Cannot Rely On EPAct-Subsidized Facilities To Meet The Adequate Demonstration Standard. Finally, EPA improperly purports to reduce its statutory burden by explicitly considering facilities to support its adequate demonstration analysis that are excluded under federal law. EPAct authorizes federal assistance in the form of grants, loan guarantees, and federal tax credits for investment in certain types of energy technology. 80 Fed. Reg. at 64,541, JA___. But it also contains three separate provisions—sections 402(i) (covering facilities receiving assistance under the Energy 4 Although not relevant here, State Petitioners demonstrated in their briefs challenging EPA’s Power Plan Rule that there are other independent limitations on what can qualify as a “system” under CAA. Dkt. 1608991, at *13-15, West Virginia v. EPA, No. 15-1363 (D.C. Cir. filed April 15, 2016). 19 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 40 of 67 Policy Act of 2005), 421(a) (adding sections 3103(e) and 3104(d) to the Energy Policy Act of 1992 to cover facilities receiving assistance under the Clean Air Coal Program), and 1307(b) (adding section 48A(g) to the Internal Revenue Code to cover facilities receiving the Qualifying Advanced Coal Project Credit)—that contain substantively identical language prohibiting EPA from considering any EPAct-assisted facilities when determining whether a particular system has been adequately demonstrated. EPA admits that these related provisions “were part of the same legislation and address the same issue,” and that there is no “indicati[on] that they were meant to have different meanings.” EPAct TSD at 13, JA___. One representative section, and the last to be enacted into law, provides that: No use of technology (or level of emission reduction solely by reason of the use of the technology), and no achievement of any emission reduction by the demonstration of any technology or performance level, by or at one or more facilities with respect to which a credit is allowed under this section, shall be considered to indicate that the technology or performance level is ... adequately demonstrated for purposes of section 111 of the Clean Air Act .... 26 U.S.C. § 48A(g); see also 42 U.S.C. §§ 13573(e), 13574(d), 15962(i). In interpreting this statute, EPA admits that the provisions collectively cover any “technology or emissions reduction for which assistance was given” or the “credit is allowed.” 80 Fed. Reg. at 64,541, JA___. EPA nonetheless attempts to parse each of these provisions to reach its strained and implausible reading of the statute. That is, EPA concludes that these provisions merely “bar[] consideration where EPAct[]assisted facilities were the sole support for the BSER determination,” but permit 20 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 41 of 67 consideration to “support a BSER determination so long as there is additional evidence supporting the determination.” Id.5 EPA makes two arguments in support of this reading, neither of which comport with the plain language of the statute. First, EPA argues that the phrase “considered to indicate,” which appears only in section 48A(g), should be interpreted to mean “deemed to prove.” Response to Comment at 2-122, EPA-HQ-OAR-2013-0495-11861, JA___; Chloe Kolman Memorandum to Section 111(b) Docket on EPAct05 at 5 (July 29, 2015), EPA-HQOAR-2013-0495-11334, JA___. This reading, however, is plainly erroneous. The term “considered,” when directed at EPA, has been interpreted as a direction to that agency to take a particular factor into account. Ethyl Corp. v. EPA, 541 F.2d 1, 32 n.66 (D.C. Cir. 1976) (mandatory “consideration” of factors requires “actual good faith consideration of the specified evidence and options”). EPA’s contorted interpretation, which would permit it to “consider” EPAct-assisted facilities so long they are not “deemed to prove” a technology is adequately demonstrated, cannot be accepted. Second, EPA argues that the phrase “solely by reason of,” as it appears in sections 402(i) and 421(a) (but not section 48A(g)), indicates that EPA can “rely on information from EPAct[] facilities even where that information is a necessary component of its determination, so long as the information from these facilities is not 5 Contrary to EPA’s assertion, its interpretations of EPAct are due no deference, because EPAct is not a statute that EPA has been “entrusted to administer.” Chevron, U.S.A., Inc. v. Natural Res. Def. Council, 467 U.S. 837, 844 (1984); see also SW General, Inc. v. Nat’l Labor Relations Bd., 796 F.3d 67, 74 n.4 (D.C. Cir. 2015). 21 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 42 of 67 the sole support for the determination.” Response to Comments at 2-118 to 2-120, EPA-HQ-OAR-2013-0495-11861, JA___,___; see also 80 Fed. Reg. at 64541, JA___. But EPA’s interpretation is contrary to the plain meaning of the statute. If consideration of EPAct-assisted pilot-scale projects is a deciding factor that tips the balance in favor of EPA finding a technology to be adequate demonstrated, then EPA’s adequate demonstration determination is “solely by reason of” its consideration of the pilot-scale projects. In other words, EPA would not have been able to make a finding of adequate demonstration but for the pilot-scale projects. Thus, EPA is prohibited from considering covered facilities to support the Rule. EPA effectively claims that the phrase “solely by reason of” introduces a “mixed motive” standard of causation, whereby EPA can consider covered facilities as long as it considers any other evidence not covered by EPAct. But courts have rejected this narrow meaning of “solely by reason of” where context shows that Congress intended to adopt a “but-for” causation standard. See, e.g., Price Waterhouse v. Hopkins, 490 U.S. 228, 241 (1989) (absence of word “solely” in Title VII indicated that Congress intended to adopt mixed-motive standard, rather than but-for standard); Severino v. N. Fort Myers Fire Control Dist., 935 F.2d 1179, 1184-85 (11th Cir. 1991) (prohibition in Rehabilitation Act against discrimination “solely by reason of ... handicap,” 29 U.S.C. § 794(a), must signify “but-for” cause or similar standard). Applying the proper standard, EPA must show that it would have made the same decision in the absence of considering any EPAct-assisted facilities. 22 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 43 of 67 This is the only interpretation that makes sense when reading the words “‘in ... context and with a view to their place in the overall statutory scheme.’” King v. Burwell, 135 S. Ct. 2480, 2489 (2015) (quoting FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120, 133 (2000)). Otherwise, EPA could always circumvent EPAct merely by pointing to some small article of additional evidence to support its adequate demonstration analysis. Indeed, EPA does not dispute that under its reading of the statute, it could avoid EPAct’s restrictions by “including a mere scintilla of evidence from non-EPAct05 facilities,” but merely asserts that such an “extreme hypothetical ... is not presented here.” 80 Fed. Reg. at 64,541, JA___. This Court should not allow an interpretation that would undermine Congress’s goal of precluding EPA from relying on government-subsidized facilities. C. To The Extent That There Is Any Ambiguity As To EPA’s Burden, The CAA And EPAct Should Be Interpreted To Prevent EPA From Intruding On The States’ Traditional Authority Over Energy Production. If there were any doubt as to the proper interpretation of EPAct or of section 111 of the CAA, such doubt should be resolved in favor of State Petitioners’ reading, which protects the States’ traditional interest in energy policy from federal encroachment. It is a “well-established principle that it is incumbent upon the federal courts to be certain of Congress’ intent before finding that federal law overrides the usual constitutional balance of federal and state powers.” Bond v. United States, 134 S. Ct. 2077, 2089 (2014) (internal quotations omitted). “This principle applies when 23 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 44 of 67 Congress ‘intends to pre-empt the historic powers of the States’ or when it legislates in ‘traditionally sensitive areas’ that ‘affec[t] the federal balance.’” Raygor v. Regents of Univ. of Minn., 534 U.S. 533, 544 (2002). The statutes, as interpreted by EPA, cannot be squared with that principle. EPA’s interpretation of section 111(b) and EPAct would allow it to promulgate emission requirements premised on technology that is commercially available nowhere in the world. In practical effect, this would require States either to expend enormous sums on highly experimental and costly control technology or else abandon coal in favor of EPA’s preferred forms of energy generation. Under either option, EPA’s interpretation of section 111 effectively usurps the long-recognized authority that States possess over significant “questions of need, reliability, cost and other related state concerns” in the “field of regulating electrical utilities.” Pac. Gas, 461 U.S. at 205. The States’ authority over the intrastate generation and consumption of energy is “one of the most important … functions traditionally associated with the police powers of the States.” Ark. Elec. Coop. Corp. v. Ark. Pub. Serv. Comm’n, 461 U.S. 375, 377 (1983). And historically, the “economic aspects of electrical generation”—which lie at the very heart of the Rule—“have been regulated for many years and in great detail by the states.” Pac. Gas, 461 U.S. at 206. Thus, any ambiguity in the CAA or EPAct should be read to preserve the States’ traditional authority over energy generation by requiring, at a minimum, that 24 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 45 of 67 EPA demonstrate that technology is commercially available before imposing it as a nationwide standard on new sources under section 111(b). II. EPA Failed To Show In The Record That Its BSER Is Adequately Demonstrated. A. The Record Does Not Contain Any Evidence Of Fully-Integrated, Commercial-Scale Operations. Had EPA applied the correct legal standard, it could not have provided an adequate justification for the Rule, because the record reflects that EPA’s selected BSER is not commercially available anywhere in the world. Therefore, the Rule must be vacated. Most of the evidence that EPA cites to support the Rule cannot be considered once the correct legal standard is applied. EPA concedes, as it must, that it “prominently discussed” several facilities in the proposed rule (Kemper, Hydrogen Energy California Project, and Texas Clean Energy Project) that received both Clean Coal Power Initiative funding and section 48A tax credit allocations, and were therefore covered by EPAct. EPAct TSD at 20, JA___; 79 Fed. Reg. 10,750 (Feb. 26, 2014), JA___; 80 Fed. Reg. at 64,526 & n.74, JA___. But as explained above, EPA cannot justify the Rule unless it can show that it would have selected the same BSER even had it not unlawfully “considered” these highly-subsidized facilities.6 6 As Non-State Petitioners explain (Non-State Br. Part I.A.), EPA would not have satisfied its burden even if it could consider EPAct-funded facilities. None of these projects is fully operational. Additionally, all three would substantially deviate from EPA’s BSER, because they would use IGCC technology rather than SCPC, and would 25 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 46 of 67 EPA also relies on a handful of small-scale demonstration projects that reflect non-utility operations, include only one component of the CCS system, or have not been completed, in an effort to show that partial CCS is “feasible.” Id. at 64,550-56, JA___-___. But as noted above, these small demonstration projects cannot meet the adequate demonstration standard where, as here, they are not “representative of full scale performance,” Costle, 657 F.2d at 382, and are not bolstered by other evidence of full-scale viability. See Non-State Br. I.A. EPA also relies on vendor guarantees to support its technical feasibility finding, but admits that “it is unlikely that a single technology vendor would provide a guarantee for ‘the system as a whole.’” 80 Fed. Reg. at 64,555, JA___. EPA cannot rely on vendor guarantees relating to particular component parts to show that the fully-integrated “system” had been adequately demonstrated. See Essex, 486 F.2d at 440; Costle, 657 F.2d at 364. Eliminating EPAct-covered facilities, pilot-scale facilities, and vendor guarantees, EPA’s sole purported evidence of an operating commercial-scale CCS system at an EGU is Boundary Dam.7 See 80 Fed. Reg. 64,549–50, JA___-___. EPA inject the CO2 for enhanced oil recovery purposes rather than into deep saline formations. See id. 7 EPA identifies Dakota Gasification, which did not receive EPAct funding, as a “fullscale commercial operation that is successfully implementing pre-combustion CCS technology.” 80 Fed. Reg. at 64,556, JA___. But as a pre-combustion process that manufactures natural gas, Dakota Gasification does not generate power and is not representative of the operations of a full-scale commercial system. See Comments of 26 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 47 of 67 concludes that Boundary Dam, by itself, shows the “technical feasibility of full-scale, fully integrated implementation of available post-combustion CCS technology, which in this case also appears to be commercially viable.” Id. at 64,550, JA___. But Boundary Dam cannot bear the weight that EPA assigns to it. As further discussed by Non-State Petitioners (see Non-State Br. at I.A.), Boundary Dam is a small-scale facility that does not incorporate all elements of EPA’s BSER, such as sequestration in deep saline formations. Id. at 64,556; JA___. It has also been heavily reliant on financial assistance from both the Canadian federal government and Saskatchewan provincial government. Id. at 64,550–51, JA___-__. It therefore implicates the same concerns as the EPAct facilities that Congress expressly forbade EPA to consider, namely, it provides no evidence that the enterprise would be commercially viable for full-scale, non-subsidized plants. Because EPA “has relied on factors which Congress has not intended it to consider” in touting Boundary Dam as commercially available technology, it has acted arbitrarily and capriciously. Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983). B. EPA Fails To Meet Even Its Incorrect, Reduced Legal Standard. EPA’s BSER would fail even if its reduced evidentiary burden—showing technical feasibility of component parts—were the law. See Non-State Br. I.A. Of the Utility Air Regulatory Group, EPA-HQ-OAR-2013-0495, at 5 (May 9, 2014), JA___. 27 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 48 of 67 particular importance to State Petitioners, EPA has utterly failed to demonstrate the technical feasibility of storage in deep saline formations on a nationwide basis. For a “system of ... emission reduction” to be “demonstrated,” EPA must show that the system can be implemented on a nation-wide basis. Costle, 657 F.2d at 330. But as EPA recognizes, “whether all new steam-generating sources can implement” its BSER is “dependent on the geographic scope,” 80 Fed. Reg. at 64,541, JA___, and large areas of the U.S.—11 States and parts of many more—do not have any identified deep saline formations, id. at 64,576-77, JA___-___. Formations that may be accessible in the remaining States have not been demonstrated to be capable of permanent storage.8 In fact, EPA acknowledges that not all formations are suitable for sequestration, that site-specific evaluations are critical to selecting a geological site that can permanently contain injected CO2, id. at 64,573, JA___, and that no effort has been made to identify formations that are capable of permanent sequestration. In addition, there is no established industry sector operating deep saline formations demonstrated to be capable of permanent CO2 storage. Developers of new fossil-fuel-fired units thus face significant unknowns in determining how and where to site new units. 8 The State of Wisconsin filed a Petition for Reconsideration regarding this issue. See Request for Reconsideration of New Source Performance Standards (NSPS) for Greenhouse Gas Emissions From Stationary Sources: Electric Utility Steam Generating Units, Docket ID No. EPA-HQ-OAR-2013-0495 (Dec. 22, 2015), http://dnr.wi.gov/topic/AirQuality/documents/WI111bReconsiderationRequest201 51222.pdf (“WI Petition”), JA___-___. 28 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 49 of 67 Furthermore, no CO2 pipeline system exists to transport CO2 throughout the country, and the development of any such system will be costly and time-consuming. For States such as Wisconsin that lack proven sequestration resources, EPA failed to consider the costs of transporting captured CO2 to sequestration sites. WI Petition at 2, JA___; see also EPA, Basis for Denial of Petitions to Reconsider CAA Section 111(b) Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Utility Generating Units (April 2016), at 6, JA___. Until deep saline formation disposal sites capable of permanent sequestration are identified, developed, and tested by developers of such facilities, and until the pipeline infrastructure is developed to move CO2 to such sites, even this component of EPA’s system cannot be shown to be “adequately demonstrated.”9 III. A. EPA Failed To Adequately Consider The Costs And Benefits Of The Rule. EPA Has A Statutory Obligation To Consider Costs And Benefits Under The CAA. The CAA requires EPA to consider costs and benefits before imposing a nationwide standard under section 111(b). EPA has failed to adequately satisfy this 9 EPA argues that any issue regarding geographic availability of geologic sequestration is “moot[ed]” by EPA’s assessment that new utility boilers and IGCC units can “cofir[e] with natural gas in lieu of installing partial CCS.” 80 Fed. Reg. at 64,541, JA___. But EPA admits that co-firing is not part of its BSER, id. at 64,514, JA___, and therefore it cannot moot EPA’s burden to adequately demonstrate its BSER which specifically includes sequestration in “deep saline formations,” id. at 64,579, JA___. 29 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 50 of 67 statutory prerequisite, which provides another, independent basis for vacating the Rule. Section 111 requires EPA to “tak[e] into account the costs of achieving such [emission] reduction,” 42 U.S.C. § 7411(a)(1), which “clearly refers to the possible economic impact of the promulgated standards,” Portland Cement, 486 F.2d. at 387. To be “adequately demonstrated,” therefore, a system cannot be “exorbitantly costly in an economic ... way.” Essex, 486 F.2d at 433; see also Lignite Energy Council, 198 F.3d at 933; Portland Cement Ass’n v. Train, 513 F.2d 506, 508 (D.C. Cir. 1975). EPA must consider not only the costs of installation and maintenance, but also whether those costs would be passed on to consumers. See, e.g., Portland Cement, 486 F.2d at 387-88. EPA cannot simply consider these costs in a vacuum; rather, it must determine whether any costs are justified by corresponding, offsetting benefits. The CAA limits EPA’s authority to “prescrib[ing] such regulations as are necessary to carry out” the agency’s functions. 42 U.S.C. § 7601(a)(1) (emphasis added). In interpreting analogous language elsewhere in the CAA, the Supreme Court held that EPA must, as a component of “rational” rulemaking, compare the “economic costs” of a rule to its purported “health or environmental benefits.” Michigan, 135 S. Ct. at 2707. Indeed, the current Administration has required agencies like EPA to “propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs,” and to “select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits.” Exec. Order No. 13,563, Improving 30 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 51 of 67 Regulation and Regulatory Review, 76 Fed. Reg. 3,821 (Jan. 18, 2011), JA___. Similarly, this Court has held in the analogous context of arbitrary and capricious review under the Administrative Procedure Act that it is unlawful for an agency to fail to consider a rule’s “cost[s] at the margin,” Bus. Roundtable v. SEC, 647 F.3d 1144, 1151 (D.C. Cir. 2011), or to fail to consider the existing regulatory and market “baseline” in considering whether a rule will yield any incremental benefits, Am. Equity Inv. Life Ins. Co. v. SEC, 613 F.3d 166, 177-78 (D.C. Cir. 2009). In at least two ways discussed below, EPA has failed to engage in this type of reasoned cost-benefit analysis, and therefore, has violated the CAA, requiring that the Rule be vacated. B. The Rule Should Be Vacated Because EPA Admits That The Rule Is Not Projected To Yield Any Benefits. First, EPA effectively concedes that the Rule is not “necessary” to carry out the purposes of the CAA (42 U.S.C. § 7601(a)(1)), by admitting that the Rule “will result in negligible CO2 emission changes, quantified benefits, and costs by 2022 as a result of the performance standards for newly constructed EGUs.” 80 Fed. Reg. at 64,515, JA___. EPA predicts that “the owners of newly constructed EGUs will likely choose technologies, primarily [natural gas combined cycle], which meet the standards even in the absence of this rule due to existing economic conditions as normal business practice.” Id. at 64,640, JA___. 31 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 52 of 67 EPA cannot impose a nationwide emission standard on all new fossil-fuel-fired steam generating units if it does not believe that the Rule is likely to actually result in reduced levels of pollution. This Court has rejected similar attempts by agencies to promulgate superfluous rules where the “baseline” level of regulation would produce the same effect. See, e.g., Am. Equity, 613 F.3d at 177-78. EPA’s conclusion that the Rule is unnecessary under prevailing economic conditions alone renders it unlawful. C. The Rule Should Be Vacated Because EPA’s BSER Is Exorbitantly Costly And Therefore Has Not Been Adequately Demonstrated. A second, independent failure by EPA is that it dramatically underestimated the Rule’s costs. EPA failed to recognize that it would be “exorbitantly costly” for a new source to actually implement EPA’s BSER. Essex, 486 F.2d at 433. EPA claims that any costs will be “negligible” because “substantial new construction of uncontrolled fossil steam units is not anticipated under existing prevailing and anticipated future economic conditions.” 80 Fed. Reg. at 64,563, JA___. But EPA cannot minimize potential costs by arguing that the Rule will not have its intended effect. EPA’s rationale “is tantamount to saying the saving grace of the rule is that it will not entail costs if it is not used,” which this Court has described as “unutterably mindless.” Bus. Roundtable, 647 F.3d at 1156. Assuming that the Rule will actually be applied to new sources, as EPA must, the costs to such sources and to energy consumers are prohibitive. The projects cited by EPA that feature some form of CCS technology are more expensive than originally 32 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 53 of 67 estimated and depend on government subsidies. For example, at the Kemper facility in Mississippi, total project costs have risen significantly from their original estimates, and, despite receiving substantial federal funding, the project is several years behind schedule. In fact, the facility is not yet fully operational. Moreover, Kemper is dependent on numerous “site-specific characteristics” that “cannot be consistently replicated on a national level.” Comments of Southern Company, EPA-HQ-OAR2013-0495-10101, at 22 (May 9, 2014), JA____. Boundary Dam, likewise, despite being less than one-quarter the size of a full-scale power plant, has incurred a total cost of C$1.24 billion and required C$240 million in subsidies from the Canadian federal and Saskatchewan provincial governments, as well as proceeds from sales of carbon captured, merely to stay afloat. Comments of Utility Air Regulatory Group, EPA-HQ-OAR-2013-0495-10938, at 129 (May 9, 2014), JA___. Furthermore, Deputy Assistant Secretary of Energy Julio Friedmann confirmed in congressional testimony the exorbitant costs associated with CCS and testified that CCS would increase electricity prices by as much as 80%. West Virginia Comments, at 6, JA__. EPA and the Congressional Budget Office have made similar findings. See 77 Fed. Reg. 22,391, 22,415-16 (Apr. 13, 2012), JA___-___; Congressional Budget Office, Federal Efforts to Reduce the Cost of Capturing and Storing Carbon Dioxide, June 2012, at 7-9, JA___-___. EPA’s failure to meaningfully consider these costs, and to reject this system in light of the significant costs to new sources and negligible projected environmental benefits, requires that the Rule be vacated. 33 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 54 of 67 The record also reflects that gas-fired units have been treated differently from coal-fired units. “Inter-industry comparison in the case of industries producing substitute or alternative products ... bears on the issue of ‘economic cost.’” Portland Cement, 486 F.2d at 390. EPA’s failure to justify its differential treatment of new baseload gas-fired units versus new baseload gas-fired units violates the CAA’s requirement to appropriately consider costs and necessitates vacatur of the Rule. See Non-State Br. II (citing Airmark Corp. v. FAA, 758 F.2d 685, 691, 694 (D.C. Cir. 1985)). IV. EPA Failed To Make The Statutorily-Required Endangerment And Significant Contribution Findings. Finally, EPA exceeded its authority by imposing a new nationwide emission standard without first making two findings required by section 111(b) of the CAA. EPA’s failure to consider these required factors renders the Rule unlawful. See State Farm, 463 U.S. at 43. Section 111(b) requires EPA to make two findings before issuing new emission limits for new sources. First, EPA must find that the air pollutant it seeks to regulate “may reasonably be anticipated to endanger public health or welfare.” 42 U.S.C. § 7411(b)(1)(A). Second, EPA must find that the source category “contributes significantly” to that endangerment. Id. EPA bypassed these straightforward prerequisites when, for the first time in the Rule, it regulated a new pollutant (CO2) from a new source category (fossil-fuel34 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 55 of 67 fired electricity generating units). To accomplish this sleight-of-hand, EPA first claimed erroneously that it previously regulated this same source category. 80 Fed. Reg. at 64,529, JA___. That is not so. See Non-State Br. IV. Separately, EPA claims that the statute empowers it to regulate any pollutant from a previously listed source category so long as it made an endangerment finding with respect to any pollutant emitted from the source category at some point in the past. See id. But EPA’s construction of the statute fails scrutiny. As a textual matter, the endangerment requirement modifies, and relates back to, “air pollution,” not “sources.” 42 U.S.C. § 7411(b)(1)(A). Only when EPA determines that a particular pollutant poses a threat to health or welfare must the agency inquire whether the “sources” significantly contribute to that pollution. See id. Any other reading, in context, would impermissibly modify and undermine the entire statutory scheme. Cf. Burwell, 135 S. Ct. at 2489. It would make no sense for Congress to have provided EPA with a blank check to regulate multiple pollutants from a given source category so long as it had initially made an endangerment finding with respect to a single, unrelated pollutant. But that is the logical result of EPA’s interpretation. Ultimately, EPA recognizes that its reading of the statute cannot be correct, because it adopts and applies an extra-textual test that it claims should apply when it regulates new pollutants from previously-listed source categories, i.e., that EPA needs 35 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 56 of 67 a “rational basis” for the Rule. 80 Fed. Reg. 64,530, JA___. EPA’s invented test exceeds its discretion under the CAA, however, for multiple independent reasons. First, EPA cannot adopt a new standard that has no mooring whatsoever in the text of the CAA, and indeed, conflicts with the standard that the CAA explicitly adopts for the same analysis. Second, the “rational basis” test also undermines the structure of the statute in the same way as EPA’s principal position that the CAA imposes no endangerment requirement for new pollutants from previously-listed sources. It is implausible that Congress would have imposed one, more rigorous standard to whatever pollutant EPA decided to regulate first from a listed source category, and then one more relaxed standard for whatever subsequent pollutants EPA decided to regulate from that same source category. That conclusion is confirmed by other endangerment provisions in the CAA, which EPA concedes require findings for each specific pollutant. 80 Fed. Reg. at 64,530 (citing the CAA §§ 202(a)(1), 211(c)(1), 231(a)(2)(A)), JA____. Third, a “rational basis” test does not address the key question that the endangerment findings were designed to answer, namely, the scientific inquiry into whether a particular pollutant causes significant harm to health or welfare. See Coal. for Responsible Regulation, 684 F.3d 102, 118 (D.C. Cir. 2012). Instead, the “rational basis” test is a standard of review that asks whether the government’s selected policy has “some legitimate governmental purpose.” Heller v. Doe, 509 U.S. 312, 320 (1993). The 36 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 57 of 67 Supreme Court, however, has “rebuffed an[y] attempt by EPA itself to inject considerations of policy into its [emission] decision[s],” because “[t]he statute speaks in terms of endangerment, not in terms of policy.” Coal. for Responsible Regulation, 684 F.3d at 118 (citing Massachusetts v. EPA, 549 U.S. 497, 534-35 (2007)). Thus, EPA’s invented “rational basis” test addresses itself to the wrong question, and this Court should reject it. CONCLUSION For the foregoing reasons, the petitions should be granted and the Rule vacated. 37 USCA Case #15-1381 Document #1640985 Dated: October 13, 2016 Filed: 10/13/2016 Page 58 of 67 Respectfully submitted, /s/ Elbert Lin Patrick Morrisey Attorney General of West Virginia Elbert Lin Solicitor General Counsel of Record Thomas M. Johnson, Jr. Deputy Attorney General Katlyn M. Miller Assistant Attorney General State Capitol Building 1, Room 26-E Tel. (304) 558-2021 Fax (304) 558-0140 Email: elbert.lin@wvago.gov Counsel for Petitioner State of West Virginia 38 USCA Case #15-1381 Document #1640985 /s/ Andrew Brasher Luther Strange ATTORNEY GENERAL OF ALABAMA Andrew Brasher Solicitor General Counsel of Record 501 Washington Avenue Montgomery, AL 36130 Tel: (334) 353-2609 abrasher@ago.state.al.us Counsel for Petitioner State of Alabama Filed: 10/13/2016 Page 59 of 67 /s/ John R. Lopez IV Mark Brnovich ATTORNEY GENERAL OF ARIZONA John R. Lopez IV Counsel of Record Dominic E. Draye Deputy Solicitor General Keith Miller Assistant Attorney General Maureen Scott Janet Wagner Janice Alward Arizona Corp. Commission, Staff Attorneys 1275 West Washington Phoenix, AZ 85007 Tel: (602) 542-5025 john.lopez@azag.gov dominic.draye@azag.gov keith.miller@azag.gov Counsel for Petitioner Arizona Corporation Commission 39 USCA Case #15-1381 Document #1640985 /s/ Lee Rudofsky Leslie Rutledge ATTORNEY GENERAL OF ARKANSAS Lee Rudofsky Solicitor General Counsel of Record Jamie L. Ewing Assistant Attorney General 323 Center Street, Suite 400 Little Rock, AR 72201 Tel: (501) 682-5310 jamie.ewing@arkansasag.gov Counsel for Petitioner State of Arkansas Filed: 10/13/2016 Page 60 of 67 /s/ Jonathan L. Williams Pamela Jo Bondi ATTORNEY GENERAL OF FLORIDA Jonathan L. Williams Deputy Solicitor General Counsel of Record Jonathan A. Glogau Special Counsel Office of the Attorney General PL-01, The Capitol Tallahassee, FL 32399-1050 Tel: (850) 414-3300 Fax: (850) 410-2672 jonathan.williams@myfloridalegal.com Counsel for Petitioner State of Florida /s/ Britt C. Grant Samuel S. Olens ATTORNEY GENERAL OF GEORGIA Britt C. Grant Solicitor General Counsel of Record 40 Capitol Square S.W. Atlanta, GA 30334 Tel: (404) 656-3300 Fax: (404) 463-9453 bgrant@law.ga.gov Counsel for Petitioner State of Georgia /s/ Timothy Junk Gregory F. Zoeller ATTORNEY GENERAL OF INDIANA Timothy Junk Deputy Attorney General Counsel of Record Indiana Government Ctr. South Fifth Floor 302 West Washington Street Indianapolis, IN 46205 Tel: (317) 232-6247 tim.junk@atg.in.gov Counsel for Petitioner State of Indiana 40 USCA Case #15-1381 Document #1640985 /s/ Jeffrey A. Chanay Derek Schmidt ATTORNEY GENERAL OF KANSAS Jeffrey A. Chanay Chief Deputy Attorney General Counsel of Record Bryan C. Clark Assistant Solicitor General 120 S.W. 10th Avenue, 3rd Floor Topeka, KS 66612 Tel: (785) 368-8435 Fax: (785) 291-3767 jeff.chanay@ag.ks.gov bryan.clark@ag.ks.gov Counsel for Petitioner State of Kansas /s/ Steven B. “Beaux” Jones Jeff Landry ATTORNEY GENERAL OF LOUISIANA Steven B. “Beaux” Jones Counsel of Record Environmental Section – Civil Division 1885 N. Third Street Baton Rouge, LA 70804 Tel: (225) 326-6085 Fax: (225) 326-6099 jonesst@ag.state.la.us Counsel for Petitioner State of Louisiana Filed: 10/13/2016 Page 61 of 67 /s/ Joseph A. Newberg, II Andy Beshear ATTORNEY GENERAL OF KENTUCKY Mitchel T. Denham Assistant Deputy Attorney General Joseph A. Newberg, II Assistant Attorney General Counsel of Record 700 Capital Avenue Suite 118 Frankfort, KY 40601 Tel: (502) 696-5611 joe.newberg@ky.gov Counsel for Petitioner Commonwealth of Kentucky /s/ Donald Trahan Herman Robinson Executive Counsel Donald Trahan Counsel of Record Spencer Bowman Elliott Vega LOUISIANA DEPARTMENT OF ENVIRONMENTAL QUALITY Legal Division P.O. Box 4302 Baton Rouge, LA 70821-4302 Tel: (225) 219-3985 Fax: (225) 219-4068 donald.trahan@la.gov elliott.vega@la.gov Counsel for Petitioner State of Louisiana Department of Environmental Quality 41 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 62 of 67 /s/ Aaron D. Lindstrom Bill Schuette ATTORNEY GENERAL FOR THE PEOPLE OF MICHIGAN Aaron D. Lindstrom Michigan Solicitor General Counsel of Record Neil D. Gordon Assistant Attorney General P.O. Box 30212 Lansing, MI 48909 Tel: (515) 373-1124 Fax: (517) 373-3042 lindstroma@michigan.gov /s/ James R. Layton Chris Koster ATTORNEY GENERAL OF MISSOURI James R. Layton Solicitor General Counsel of Record Laura Elsbury Assistant Attorney General P.O. Box 899 207 W. High Street Jefferson City, MO 65102 Tel: (573) 751-1800 Fax: (573) 751-0774 james.layton@ago.mo.gov Counsel for Petitioner People of the State of Michigan Counsel for Petitioner State of Missouri /s/ Dale Schowengerdt Timothy C. Fox ATTORNEY GENERAL OF MONTANA Alan Joscelyn Chief Deputy Attorney General Dale Schowengerdt Solicitor General Counsel of Record 215 North Sanders Helena, MT 59620-1401 Tel: (406) 444-7008 dales@mt.gov /s/ Justin D. Lavene Douglas J. Peterson ATTORNEY GENERAL OF NEBRASKA Dave Bydalek Chief Deputy Attorney General Justin D. Lavene Assistant Attorney General Counsel of Record 2115 State Capitol Lincoln, NE 68509 Tel: (402) 471-2683 justin.lavene@nebraska.gov Counsel for Petitioner State of Montana Counsel for Petitioner State of Nebraska 42 USCA Case #15-1381 Document #1640985 /s/ Sam M. Hayes Sam M. Hayes General Counsel Counsel of Record Craig Bromby Deputy General Counsel Andrew Norton Deputy General Counsel NORTH CAROLINA DEPARTMENT OF ENVIRONMENTAL QUALITY 1601 Mail Service Center Raleigh, NC 27699-1601 Tel: (919) 707-8616 sam.hayes@ncdenr.gov Filed: 10/13/2016 Page 63 of 67 /s/ Eric E. Murphy Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ohioattorneygeneral.gov Counsel for Petitioner State of Ohio Counsel for Petitioner North Carolina Department of Environmental Quality /s/ P. Clayton Eubanks E. Scott Pruitt ATTORNEY GENERAL OF OKLAHOMA Patrick R. Wyrick Solicitor General P. Clayton Eubanks Deputy Solicitor General Counsel of Record 313 N.E. 21st Street Oklahoma City, OK 73105 Tel: (405) 521-4396 Fax: (405) 522-0669 clayton.eubanks@oag.ok.gov Counsel for Petitioner State of Oklahoma /s/ James Emory Smith, Jr. Alan Wilson ATTORNEY GENERAL OF SOUTH CAROLINA Robert D. Cook Solicitor General James Emory Smith, Jr. Deputy Solicitor General Counsel of Record P.O. Box 11549 Columbia, SC 29211 Tel: (803) 734-3680 Fax: (803) 734-3677 esmith@scag.gov Counsel for Petitioner State of South Carolina 43 USCA Case #15-1381 Document #1640985 /s/ Steven R. Blair Marty J. Jackley ATTORNEY GENERAL OF SOUTH DAKOTA Steven R. Blair Assistant Attorney General Counsel of Record 1302 E. Highway 14, Suite 1 Pierre, SD 57501 Tel: (605) 773-3215 steven.blair@state.sd.us Counsel for Petitioner State of South Dakota Filed: 10/13/2016 Page 64 of 67 /s/ Scott A. Keller Ken Paxton ATTORNEY GENERAL OF TEXAS Jeffrey C. Mateer First Assistant Attorney General Scott A. Keller Solicitor General Counsel of Record P.O. Box 12548 Austin, TX 78711-2548 Tel: (512) 936-1700 scott.keller@texasattorneygeneral.gov Counsel for Petitioner State of Texas /s/ Tyler R. Green Sean Reyes ATTORNEY GENERAL OF UTAH Tyler R. Green Solicitor General Counsel of Record Parker Douglas Chief Federal Deputy Utah State Capitol Complex 350 North State Street, Suite 230 Salt Lake City, UT 84114-2320 tylergreen@utah.gov pdouglas@utah.gov Counsel for Petitioner State of Utah /s/ Misha Tseytlin Brad Schimel ATTORNEY GENERAL OF WISCONSIN Misha Tseytlin Solicitor General Counsel of Record Andrew Cook Deputy Attorney General Delanie M. Breuer Assistant Deputy Attorney General Wisconsin Department of Justice 17 West Main Street Madison, WI 53707 Tel: (608) 267-9323 tseytlinm@doj.state.wi.us Counsel for Petitioner State of Wisconsin 44 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 /s/ James Kaste Peter K. Michael ATTORNEY GENERAL OF WYOMING James Kaste Deputy Attorney General Counsel of Record Michael J. McGrady Erik Petersen Senior Assistant Attorneys General Elizabeth Morrisseau Assistant Attorney General 2320 Capitol Avenue Cheyenne, WY 82002 Tel: (307) 777-6946 Fax: (307) 777-3542 james.kaste@wyo.gov Counsel for Petitioner State of Wyoming 45 Page 65 of 67 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 66 of 67 CERTIFICATE OF COMPLIANCE Pursuant to Rule 32(a)(7)(C) of the Federal Rules of Appellate Procedure and Circuit Rules 32(a)(1) and 32(a)(2)(C), I hereby certify that the foregoing State Petitioners’ Opening Brief contains 8,897 words, as counted by a word processing system that includes headings, footnotes, quotations, and citations in the count, and therefore is within the word limit set by the Court. Dated: October 13, 2016 /s/ Elbert Lin Elbert Lin 46 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 67 of 67 CERTIFICATE OF SERVICE I hereby certify that, on this 13th day of October 2016, a copy of the foregoing State Petitioners’ Opening Brief was served electronically through the Court’s CM/ECF system on all ECF-registered counsel. /s/ Elbert Lin Elbert Lin 47 USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 1 of 44 ORAL ARGUMENT NOT YET SCHEDULED No. 15-1381 (and consolidated cases) ______________________________________ IN THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT _______________________________________ STATE OF NORTH DAKOTA, et al., V. Petitioners, UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, et al., Respondents. ______________________________________ On Petition for Review of Final Agency Actions of the United States Environmental Protection Agency 80 Fed. Reg. 64,510 (Oct. 23, 2015) and 81 Fed. Reg. 27,442 (May 6, 2016) ______________________________________ ADDENDUM PURSUANT TO CIRCUIT RULE 28(a)(5) TO STATE PETITIONERS’ OPENING BRIEF ______________________________________ Patrick Morrisey ATTORNEY GENERAL OF WEST VIRGINIA Elbert Lin Solicitor General Counsel of Record Thomas M. Johnson, Jr. Deputy Attorney General Katlyn M. Miller Assistant Attorney General Office of the Attorney General State Capitol Building 1, Room 26E Charleston, WV 25305 Tel: (304) 558-2021 Fax: (304) 558-0140 elbert.lin@wvago.gov Counsel for Petitioner State of West Virginia Additional Counsel listed on State Petitioners’ Opening Brief USCA Case #15-1381 Document #1640985 Filed: 10/13/2016 Page 2 of 44 TABLE OF CONTENTS Statutes: 26 U.S.C. § 48A............................................................................................................ADD-01 29 U.S.C. § 794.............................................................................................................ADD-06 42 U.S.C. § 15962.........................................................................................................ADD-09 42 U.S.C. § 7411...........................................................................................................ADD-12 42 U.S.C. § 7601...........................................................................................................ADD-19 42 U.S.C. § 7607...........................................................................................................ADD-21 42 U.S.C. § 13573.........................................................................................................ADD-27 42 U.S.C. § 13574.........................................................................................................ADD-28 Regulation: 40 C.F.R. 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GG•?SRFMPGRW! RM! NPMTGBC! NPCD, CPCLACQ! DMP! CJBCPJW! PCQGBCLRQ! ?LB! SLGRQ! DMP! BGQ?@JCB! PCQGBCLRQ! GL! ACPR?GL! QCARGML! 7! ?QQGQRCB! FMSQGLE! 02500-! 02501-! 02502-! 02503-! 02504-! 02505-! 02506-! 02507-! 02508-! Filed: 10/13/2016 RGRJC! 31•RFC! NS@JGA! FC?JRF! ?LB! UCJD?PC! ?pocjmdot-! P`n`mq\odji!ja!pidon!ajm!_dn\]g`_!a\hdgd`n-! Q`^ji_\mt!km`a`m`i^`n-! E`i`m\g!\q\dg\]dgdot!ja!pidon-! Nm`a`m`i^`!rdocdi!bmjpkn-! Nmjcd]dodji!ja!`qd^odjin-! Rm`\oh`io! ja! ^jq`m`_! n`^odji! 7! cjpndib! ijo! np]e`^o!oj!`g_`mgt!km`a`m`i^`-! Rm`\oh`io! ja! joc`m! a`_`m\ggt! \nndno`_! cjpn, dib-! [[Ajq`m`_!n`^odji!7!cjpndib&&!_`adi`_-! Qj!di!jmdbdi\g-!Nmj]\]gt!ncjpg_!]`![[kpmkjn`n!ja!n`^odji&&-! Page 31 of 44 v .03-0! Q`^-! 0251/-! Qop_t-! QS@AF?NRCP! GGG•QCPTGAC! AMMPBGL?RMPQ! DMP! CJBCPJW! ?LB! BGQ?@JCB! PCQGBCLRQ! MD! DCB, CP?JJW! ?QQGQRCB! FMSQGLE! 02520-! 02521-! P`lpdm`h`io!oj!kmjqd_`!n`mqd^`!^jjm_di\ojmn-! 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Q`^m`o\mt! di! `no\]gdncdib! m`\, nji\]g`!^mdo`md\!ajm!j^^pk\i^t!di!a`_`m\ggt!\n, ndno`_!cjpndib+!oc`!Q`^m`o\mt!nc\gg!`no\]gdnc!\! o\nf! ajm^`! oj! m`qd`r! \gg! mpg`n+! kjgd^t! no\o`, h`ion+!c\i_]jjfn+!o`^cid^\g!\nndno\i^`!h`hj, m\i_\+!\i_!joc`m!m`g`q\io!_j^ph`ion!dnnp`_!]t! oc`! B`k\moh`io! ja! Fjpndib! \i_! Sm]\i! B`q`g, jkh`io! ji! oc`! no\i_\m_n! \i_! j]gdb\odjin! bjq, ADD-29 USCA Case #15-1381 #1640985 Filed: Page 32 of 44 64648 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations XVI. Statutory Authority The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)). List of Subjects 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. 40 CFR Part 70 Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements. 40 CFR Part 71 Environmental protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements. 40 CFR Part 98 Environmental protection, Greenhouse gases and monitoring, Reporting and recordkeeping requirements. Dated: August 3, 2015. Gina McCarthy, Administrator. For the reasons stated in the preamble, title 40, chapter I, parts 60, 70, 71, and 98 of the Code of the Federal Regulations are amended as follows: PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 1. The authority citation for part 60 continues to read as follows: ■ Authority: 42 U.S.C. 7401 et seq. 2. Section 60.17 is amended by: a. Redesignating paragraphs (d) through (t) as paragraphs (e) through (u) and adding paragraph (d); ■ b. In newly redesignated paragraph (g), further redesignating paragraph (g)(15) as paragraph (g)(17) and adding paragraphs (g)(15) and (16); ■ c. In newly redesignated paragraph (h), revising paragraphs (h)(37), (42), (46), (138), (187), and (190); and ■ c. In newly redesignated paragraph (m), further redesignating paragraph (m)(1) as paragraph (m)(2) and adding paragraph (m)(1). The revisions and additions read as follows: mstockstill on DSK4VPTVN1PROD with RULES2 ■ ■ VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 § 60.17 Incorporations by reference. * * * * * (d) The following material is available for purchase from the American National Standards Institute (ANSI), 25 W. 43rd Street, 4th Floor, New York, NY 10036, Telephone (212) 642–4980, and is also available at the following Web site: http://www.ansi.org. (1) ANSI No. C12.20–2010 American National Standard for Electricity Meters—0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR approved for § 60.5535(d). (2) [Reserved] * * * * * (g) * * * (15) ASME PTC 22–2014, Gas Turbines: Performance Test Codes, (Issued December 31, 2014), IBR approved for § 60.5580. (16) ASME PTC 46–1996, Performance Test Code on Overall Plant Performance, (Issued October 15, 1997), IBR approved for § 60.5580. * * * * * (h) * * * (37) ASTM D388–99 (Reapproved 2004) ε1 Standard Classification of Coals by Rank, IBR approved for §§ 60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, 60.251, and 60.5580. * * * * * (42) ASTM D396–98, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b, 60.41c, 60.111(b), 60.111a(b), and 60.5580. * * * * * (46) ASTM D975–08a, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.41b 60.41c, and 60.5580. * * * * * (138) ASTM D3699–08, Standard Specification for Kerosine, including Appendix X1, (Approved September 1, 2008), IBR approved for §§ 60.41b, 60.41c, and 60.5580. * * * * * (187) ASTM D6751–11b, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 through X3, (Approved July 15, 2011), IBR approved for §§ 60.41b, 60.41c, and 60.5580. * * * * * (190) ASTM D7467–10, Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20), including Appendices X1 through X3, (Approved August 1, 2010), IBR approved for §§ 60.41b, 60.41c, and 60.5580. * * * * * (m) * * * (1) ISO 2314:2009(E), Gas turbines– Acceptance tests, Third edition PO 00000 Frm 00140 ADD-30 Sfmt 4700 Fmt 4701 (December 15, 2009), IBR approved for § 60.5580. * * * * * ■ 3. Part 60 is amended by adding subpart TTTT to read as follows: Subpart TTTT—Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units Applicability Sec. 60.5508 What is the purpose of this subpart? 60.5509 Am I subject to this subpart? Emission Standards 60.5515 Which pollutants are regulated by this subpart? 60.5520 What CO2 emissions standard must I meet? General Compliance Requirements 60.5525 What are my general requirements for complying with this subpart? Monitoring and Compliance Determination Procedures 60.5535 How do I monitor and collect data to demonstrate compliance? 60.5540 How do I demonstrate compliance with my CO2 emissions standard and determine excess emissions? Notifications, Reports, and Records 60.5550 What notifications must I submit and when? 60.5555 What reports must I submit and when? 60.5560 What records must I maintain? 60.5565 In what form and how long must I keep my records? Other Requirements and Information 60.5570 What parts of the general provisions apply to my affected EGU? 60.5575 Who implements and enforces this subpart? 60.5580 What definitions apply to this subpart? Table 1 of Subpart TTTT of Part 60—CO2 Emission Standards for Affected Steam Generating Units and Integrated Gasification Combined Cycle Facilities that Commenced Construction after January 8, 2014 and Reconstruction or Modification after June 18, 2014 Table 2 of Subpart TTTT of Part 60—CO2 Emission Standards for Affected Stationary Combustion Turbines that Commenced Construction after January 8, 2014 and Reconstruction after June 18, 2014 (Net Energy Output-based Standards Applicable as Approved by the Administrator) Table 3 to Subpart TTTT of Part 60— Applicability of Subpart A of Part 60 (General Provisions) to Subpart TTTT Applicability § 60.5508 subpart? What is the purpose of this This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 33 of 44 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations 64649 IGCC, or a stationary combustion turbine that commences construction after January 8, 2014 or commences modification or reconstruction after June 18, 2014. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected EGU. mstockstill on DSK4VPTVN1PROD with RULES2 § 60.5509 Am I subject to this subpart? (a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart apply to any steam generating unit, IGCC, or stationary combustion turbine that commenced construction after January 8, 2014 or commenced reconstruction after June 18, 2014 that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. The GHG standards included in this subpart also apply to any steam generating unit or IGCC that commenced modification after June 18, 2014 that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. (1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either alone or in combination with any other fuel); and (2) Serves a generator or generators capable of selling greater than 25 MW of electricity to a utility power distribution system. (b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (10) of this section. (1) Your EGU is a steam generating unit or IGCC that is currently and always has been subject to a federally enforceable permit condition limiting annual net-electric sales to no more than one-third of its potential electric output or 219,000 MWh, whichever is greater. (2) Your EGU is capable of combusting 50 percent or more nonfossil fuel and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less. (3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater. (4) Your EGU serves a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 stationary combustion turbine) is 25 MW or less. (5) Your EGU is a municipal waste combustor that is subject to subpart Eb of this part. (6) Your EGU is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part. (7) Your EGU is a steam generating unit or IGCC that undergoes a modification resulting in an hourly increase in CO2 emissions (mass per hour) of 10 percent or less (2 significant figures). Modified units that are not subject to the requirements of this subpart pursuant to this subsection continue to be existing units under section 111 with respect to CO2 emissions standards. (8) Your EGU is a stationary combustion turbine that is not capable of combusting natural gas (e.g., not connected to a natural gas pipeline). (9) The proposed Washington County EGU project described in Air Quality Permit No. 4911–303–0051–P–01–0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (10) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. Emission Standards § 60.5515 Which pollutants are regulated by this subpart? (a) The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas standard in this subpart is in the form of a limitation on emission of carbon dioxide. (b) PSD and title V thresholds for greenhouse gases. (1) For the purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 51.166(b)(48) of this chapter and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48). (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG PO 00000 Frm 00141 ADD-31 Sfmt 4700 Fmt 4701 emissions from affected facilities, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter. (3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in 40 CFR 70.2. (4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in 40 CFR 71.2. § 60.5520 What CO2 emission standard must I meet? (a) For each affected EGU subject to this subpart, you must not discharge from the affected EGU any gases that contain CO2 in excess of the applicable CO2 emission standard specified in Table 1 or 2 of this subpart, consistent with paragraphs (b), (c), and (d) of this section, as applicable. (b) Except as specified in paragraphs (c) and (d) of this section, you must comply with the applicable gross energy output standard, and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross energy output standard. For the remainder of this subpart (for sources that do not qualify under paragraphs (c) and (d) of this section), where the term ‘‘gross or net energy output’’ is used, the term that applies to you is ‘‘gross energy output.’’ (c) As an alternate to meeting the requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, beginning on the date the Administrator grants the petition, the affected EGU must comply with the applicable net energy output-based standard included in this subpart. Your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the remainder of this subpart, where the term ‘‘gross or net energy output’’ is used, the term that applies to you is ‘‘net energy output.’’ Owners or E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 34 of 44 64650 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations Where: mstockstill on DSK4VPTVN1PROD with RULES2 CO2 emission standard = the emission standard during the compliance period in units of lb/MMBtu. HTIPng = the heat input in MMBtu from natural gas. HTIPo = the heat input in MMBtu from all fuels other than natural gas. 120 = allowable emission rate in lb of CO2/ MMBtu for heat input derived from natural gas. 160 = allowable emission rate in lb of CO2/ MMBtu for heat input derived from all fuels other than natural gas. (b) At all times you must operate and maintain each affected EGU, including associated equipment and monitors, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the EGU. (c) Within 30 days after the end of the initial compliance period (i.e., no more than 30 days after the first 12-operatingmonth compliance period), you must VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 combustion turbines qualifying under this paragraph are only required to maintain purchase records for permitted fuels. (2) Stationary combustion turbines permitted to burn fuels that do not have a consistent chemical composition or that do not have an emission rate of 160 lb CO2/MMBtu or less (e.g., non-uniform fuels such as residual oil and non-jet fuel kerosene) must follow the monitoring, recordkeeping, and reporting requirements necessary to complete the heat input-based calculations under this subpart. General Compliance Requirements § 60.5525 What are my general requirements for complying with this subpart? Combustion turbines qualifying under § 60.5520(d)(1) are not subject to any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). For all other affected sources, compliance with the applicable CO2 emission standard of this subpart shall be determined on a 12-operating-month rolling average basis. See Table 1 or 2 make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in Table 1 or 2 of this subpart, in accordance with the requirements in this subpart. The first operating month included in the initial 12-operatingmonth compliance period shall be determined as follows: (1) For an affected EGU that commences commercial operation (as defined in § 72.2 of this chapter) on or after October 23, 2015, the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under: (i) Section 63.5555(c)(3)(i), for units subject to the Acid Rain Program; or (ii) Section 63.5555(c)(3)(ii)(A), for units that are not in the Acid Rain Program. (2) For an affected EGU that has commenced COMMERCIAL operation (as defined in § 72.2 of this chapter) prior to October 23, 2015: (i) If the date on which emissions reporting is required to begin under § 75.64(a) of this chapter has passed prior to October 23, 2015, emissions reporting shall begin according to PO 00000 Frm 00142 ADD-32 Sfmt 4700 Fmt 4701 of this subpart for the applicable CO2 emission standards. (a) You must be in compliance with the emission standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1) of this section. (1) For each affected EGU subject to a CO2 emissions standard based on a 12operating-month rolling average, you must determine compliance monthly by calculating the average CO2 emissions rate for the affected EGU at the end of the initial and each subsequent 12operating-month period. (2) Consistent with § 60.5520(d)(2), if your affected stationary combustion turbine is subject to an input-based CO2 emissions standard, you must determine the total heat input in million Btus (MMBtu) from natural gas (HTIPng) and the total heat input from all other fuels combined (HTIPo) using one of the methods under § 60.5535(d)(2). You must then use the following equation to determine the applicable emissions standard during the compliance period: § 63.5555(c)(3)(i) (for Acid Rain program units), or according to § 63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain Program). The first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which the rule becomes effective; or (ii) If the date on which emissions reporting is required to begin under § 75.64(a) of this chapter occurs on or after October 23, 2015, then the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under § 63.5555(c)(3)(ii)(A). (3) For a modified or reconstructed EGU that becomes subject to this subpart, the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under § 63.5555(c)(3)(iii). E:\FR\FM\23OCR2.SGM 23OCR2 ER23OC15.002 operators complying with the net output-based standard must petition the Administrator to switch back to complying with the gross energy outputbased standard. (d) Stationary combustion turbines subject to a heat input-based standard in Table 2 of this subpart that are only permitted to burn one or more uniform fuels, as described in paragraph (d)(1) of this section, are only subject to the monitoring requirements in paragraph (d)(1). All other stationary combustion turbines subject to a heat input based standard in Table 2 are subject to the requirements in paragraph (d)(2) of this section. (1) Stationary combustion turbines that are only permitted to burn fuels with a consistent chemical composition (i.e., uniform fuels) that result in a consistent emission rate of 160 lb CO2/ MMBtu or less are not subject to any monitoring or reporting requirements under this subpart. These fuels include, but are not limited to, natural gas, methane, butane, butylene, ethane, ethylene, propane, naphtha, propylene, jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and biodiesel. Stationary USCA Case #15-1381 #1640985 Filed: Page 35 of 44 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations 64651 Monitoring and Compliance Determination Procedures mstockstill on DSK4VPTVN1PROD with RULES2 § 60.5535 How do I monitor and collect data to demonstrate compliance? (a) Combustion turbines qualifying under § 60.5520(d)(1) are not subject to any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). If your combustion turbine uses nonuniform fuels as specified under § 60.5520(d)(2), you must monitor heat input in accordance with paragraph (c)(1) of this section, and you must monitor CO2 emissions in accordance with either paragraph (b), (c)(2), or (c)(5) of this section. For all other affected sources, you must prepare a monitoring plan to quantify the hourly CO2 mass emission rate (tons/h), in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. The electronic portion of the monitoring plan must be submitted using the ECMPS Client Tool and must be in place prior to reporting emissions data and/or the results of monitoring system certification tests under this subpart. The monitoring plan must be updated as necessary. Monitoring plan submittals must be made by the Designated Representative (DR), the Alternate DR, or a delegated agent of the DR (see § 60.5555(c)). (b) You must determine the hourly CO2 mass emissions in kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1) through (5) of this section, or, if applicable, as provided in paragraph (c) of this section. (1) For an affected coal-fired EGU or for an IGCC unit you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO2 continuous emission monitoring system (CEMS) to directly measure and record hourly average CO2 concentrations in the affected EGU exhaust gases emitted to the atmosphere, and a flow monitoring system to measure hourly average stack gas flow rates, according to § 75.10(a)(3)(i) of this chapter. As an alternative to direct measurement of CO2 concentration, provided that your EGU does not use carbon separation (e.g., carbon capture and storage), you may use data from a certified oxygen (O2) monitor to calculate hourly average CO2 concentrations, in accordance with § 75.10(a)(3)(iii) of this chapter. If you measure CO2 concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. Alternatively, you may either use an appropriate fuel-specific default VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 moisture value from § 75.11(b) or submit a petition to the Administrator under § 75.66 of this chapter for a site-specific default moisture value. (2) For each continuous monitoring system that you use to determine the CO2 mass emissions, you must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and appendices A and B to part 75 of this chapter. (3) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO2 mass emissions rate from the affected EGU; you must not apply the bias adjustment factors described in Section 7.6.5 of appendix A to part 75 of this chapter to the exhaust gas flow rate data. (4) You must select an appropriate reference method to setup (characterize) the flow monitor and to perform the ongoing RATAs, in accordance with part 75 of this chapter. If you use a Type-S pitot tube or a pitot tube assembly for the flow RATAs, you must calibrate the pitot tube or pitot tube assembly; you may not use the 0.84 default Type-S pitot tube coefficient specified in Method 2. (5) Calculate the hourly CO2 mass emissions (kg) as described in paragraphs (b)(5)(i) through (iv) of this section. Perform this calculation only for ‘‘valid operating hours’’, as defined in § 60.5540(a)(1). (i) Begin with the hourly CO2 mass emission rate (tons/h), obtained either from Equation F–11 in Appendix F to part 75 of this chapter (if CO2 concentration is measured on a wet basis), or by following the procedure in section 4.2 of appendix F to part 75 of this chapter (if CO2 concentration is measured on a dry basis). (ii) Next, multiply each hourly CO2 mass emission rate by the EGU or stack operating time in hours (as defined in § 72.2 of this chapter), to convert it to tons of CO2. (iii) Finally, multiply the result from paragraph (b)(5)(ii) of this section by 909.1 to convert it from tons of CO2 to kg. Round off to the nearest kg. (iv) The hourly CO2 tons/h values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under § 75.57(e) of this chapter and must be reported electronically under § 75.64(a)(6) of this chapter. You must use these data to calculate the hourly CO2 mass emissions. (c) If your affected EGU exclusively combusts liquid fuel and/or gaseous fuel, as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO2 mass emissions according to paragraphs (c)(1) PO 00000 Frm 00143 ADD-33 Sfmt 4700 Fmt 4701 through (4) of this section. If you use non-uniform fuels as specified in § 60.5520(d)(2), you may determine CO2 mass emissions during the compliance period according to paragraph (c)(5) of this section. (1) If you are subject to an outputbased standard and you do not install CEMS in accordance with paragraph (b) of this section, you must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) For each measured hourly heat input rate, use Equation G–4 in appendix G to part 75 of this chapter to calculate the hourly CO2 mass emission rate (tons/h). You may determine sitespecific carbon-based F-factors (Fc) using Equation F–7b in section 3.3.6 of appendix F to part 75 of this chapter, and you may use these Fc values in the emissions calculations instead of using the default Fc values in the Equation G– 4 nomenclature. (3) For each ‘‘valid operating hour’’ (as defined in § 60.5540(a)(1), multiply the hourly tons/h CO2 mass emission rate from paragraph (c)(2) of this section by the EGU or stack operating time in hours (as defined in § 72.2 of this chapter), to convert it to tons of CO2. Then, multiply the result by 909.1 to convert from tons of CO2 to kg. Round off to the nearest two significant figures. (4) The hourly CO2 tons/h values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under § 75.57(e) of this chapter and must be reported electronically under § 75.64(a)(6) of this chapter. You must use these data to calculate the hourly CO2 mass emissions. (5) If you operate a combustion turbine firing non-uniform fuels, as an alternative to following paragraphs (c)(1) through (4) of this section, you may determine CO2 emissions during the compliance period using one of the following methods: (i) Units firing fuel gas may determine the heat input during the compliance period following the procedure under § 60.107a(d) and convert this heat input to CO2 emissions using Equation G–4 in appendix G to part 75 of this chapter. (ii) You may use the procedure for determining CO2 emissions during the compliance period based on the use of the Tier 3 methodology under § 98.33(a)(3) of this chapter. (d) Consistent with § 60.5520, you must determine the basis of the emissions standard that applies to your E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 USCA Case #15-1381 #1640985 Filed: Page 36 of 44 64652 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations affected source in accordance with either paragraph (d)(1) or (2) of this section, as applicable: (1) If you operate a source subject to an emissions standard established on an output basis (e.g., lb of CO2 per gross or net MWh of energy output), you must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly gross electric output or net electric output, as applicable, from the affected EGU(s). These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20 (incorporated by reference, see § 60.17). For a combined heat and power (CHP) EGU, as defined in § 60.5580, you must also install, calibrate, maintain, and operate meters to continuously (i.e., hour-by-hour) determine and record the total useful thermal output. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record the hourly steam flow rate, temperature, and pressure. Your plan shall ensure that you install, calibrate, maintain, and operate meters to record each component of the determination, hour-by-hour. (2) If you operate a source subject to an emissions standard established on a heat-input basis (e.g., lb CO2/MMBtu) and your affected source uses nonuniform heating value fuels as delineated under § 60.5520(d), you must determine the total heat input for each fuel fired during the compliance period in accordance with one of the following procedures: (i) Appendix D to part 75 of this chapter; (ii) The procedures for monitoring heat input under § 60.107a(d); (iii) If you monitor CO2 emissions in accordance with the Tier 3 methodology under § 98.33(a)(3) of this chapter, you may convert your CO2 emissions to heat input using the appropriate emission factor in Table C–1 of part 98 of this chapter. If your fuel is not listed in Table C–1, you must determine a fuelspecific carbon-based F-factor (Fc) in accordance with section 12.3.2 of EPA Method 19 of appendix A–7 to this part, and you must convert your CO2 emissions to heat input using Equation G–4 in appendix G to part 75 of this chapter. (e) Consistent with § 60.5520, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly gross or net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 Alternatively, if the EGUs are identical, you may apportion the combined hourly gross or net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU. (f) In accordance with §§ 60.13(g) and 60.5520, if two or more affected EGUs that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard in Table 1 or 2 of this subpart, you may monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each EGU separately. If you choose this option, the hourly gross or net energy output (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual affected EGUs and you must express the operating time as ‘‘stack operating hours’’ (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected EGU sharing the stack is in compliance. (g) In accordance with §§ 60.13(g) and 60.5520 if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO2 mass emissions and the ‘‘stack operating time’’ (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in Table 1 or 2 of this subpart by summing the CO2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU. § 60.5540 How do I demonstrate compliance with my CO2 emissions standard and determine excess emissions? (a) In accordance with § 60.5520, if you are subject to an output-based emission standard or you burn nonuniform fuels as specified in § 60.5520(d)(2), you must demonstrate compliance with the applicable CO2 emission standard in Table 1 or 2 of this subpart as required in this section. For the initial and each subsequent 12operating-month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through (7) of this section to calculate the CO2 mass emissions rate for your affected EGU(s) in units of the applicable PO 00000 Frm 00144 ADD-34 Sfmt 4700 Fmt 4701 emissions standard (i.e., either kg/MWh or lb/MMBtu). You must use the hourly CO2 mass emissions calculated under § 60.5535(b) or (c), as applicable, and either the generating load data from § 60.5535(d)(1) for output-based calculations or the heat input data from § 60.5535(d)(2) for heat-input-based calculations. Combustion turbines firing non-uniform fuels that contain CO2 prior to combustion (e.g., blast furnace gas or landfill gas) may sample the fuel stream to determine the quantity of CO2 present in the fuel prior to combustion and exclude this portion of the CO2 mass emissions from compliance determinations. (1) Each compliance period shall include only ‘‘valid operating hours’’ in the compliance period, i.e., operating hours for which: (i) ‘‘Valid data’’ (as defined in § 60.5580) are obtained for all of the parameters used to determine the hourly CO2 mass emissions (kg) and, if a heat input-based standard applies, all the parameters used to determine total heat input for the hour are also obtained; and (ii) The corresponding hourly gross or net energy output value is also valid data (Note: For hours with no useful output, zero is considered to be a valid value). (2) You must exclude operating hours in which: (i) The substitute data provisions of part 75 of this chapter are applied for any of the parameters used to determine the hourly CO2 mass emissions or, if a heat input-based standard applies, for any parameters used to determine the hourly heat input; or (ii) An exceedance of the full-scale range of a continuous emission monitoring system occurs for any of the parameters used to determine the hourly CO2 mass emissions or, if applicable, to determine the hourly heat input; or (iii) The total gross or net energy output (Pgross/net) or, if applicable, the total heat input is unavailable. (3) For each compliance period, at least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section. (4) You must calculate the total CO2 mass emissions by summing the valid hourly CO2 mass emissions values from § 60.5535 for all of the valid operating hours in the compliance period. (5) Sources subject to output based standards. For each valid operating hour of the compliance period that was used in paragraph (a)(4) of this section to calculate the total CO2 mass emissions, you must determine Pgross/net (the corresponding hourly gross or net energy output in MWh) according to the E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 37 of 44 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations 64653 for an operating hour in which a valid CO2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross electrical, mechanical, or useful thermal output, you must use that hour in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads, net electric output shall be counted as zero for this calculation. (i) Calculate Pgross/net for your affected EGU using the following equation. All terms in the equation must be expressed in units of megawatt-hours (MWh). To convert each hourly gross or net energy output (consistent with § 60.5520) value reported under part 75 of this chapter to MWh, multiply by the corresponding EGU or stack operating time. energy output consists of useful thermal output on a 12-operating-month rolling average basis, or 1.0 for all other affected EGUs. selected monitoring option under § 60.5535(d)(2). (7) If you are subject to an outputbased standard, you must calculate the CO2 mass emissions rate for the affected EGU(s) (kg/MWh) by dividing the total CO2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total gross or net energy output value calculated according to the procedures in paragraph (a)(6)(i) of this section. Round off the result to two significant figures if the calculated value is less than 1,000; round the result to three significant figures if the calculated value is greater than 1,000. If you are subject to a heat input-based standard, you must calculate the CO2 mass emissions rate for the affected EGU(s) (lb/MMBtu) by dividing the total CO2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total heat input calculated according to the procedures in paragraph (a)(6)(ii) of this section. Round off the result to two significant figures. (b) In accordance with § 60.5520, to demonstrate compliance with the applicable CO2 emission standard, for the initial and each subsequent 12operating-month compliance period, the CO2 mass emissions rate for your affected EGU must be determined according to the procedures specified in paragraph (a)(1) through (7) of this section and must be less than or equal to the applicable CO2 emissions standard in Table 1 or 2 of this part, or the emissions standard calculated in accordance with § 60.5525(a)(2). Pgross/net = In accordance with § 60.5520, gross or net energy output of your affected EGU for each valid operating hour (as defined in § 60.5540(a)(1)) in MWh. (Pe)ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. (Pe)IE = Electric energy output plus mechanical energy output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (Pe)FW = Electric energy used to power boiler feedwater pumps at steam generating units in MWh. Not applicable to stationary combustion turbines, IGCC EGUs, or EGUs complying with a net energy output based standard. (Pe)A = Electric energy used for any auxiliary loads in MWh. Not applicable for determining Pgross. (Pt)PS = Useful thermal output of steam (measured relative to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh. (Pt)HR = Non steam useful thermal output (measured relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. (Pt)IE = Useful thermal output (relative to SATP conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh. TDF = Electric Transmission and Distribution Factor of 0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 (ii) If applicable to your affected EGU (for example, for combined heat and power), you must calculate (Pt)PS using the following equation: Where: Qm = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating hour. H = Enthalpy of the steam at measured temperature and pressure (relative to SATP conditions or the energy in the condensate return line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb). CF = Conversion factor of 3.6 × 109 J/MWh or 3.413 × 106 Btu/MWh. (6) Calculation of annual basis for standard. Sources complying with energy output-based standards must calculate the basis (i.e., denominator) of their actual annual emission rate in accordance with paragraph (a)(6)(i) of this section. Sources complying with heat input based standards must calculate the basis of their actual annual emission rate in accordance with paragraph (a)(6)(ii) of this section. (i) In accordance with § 60.5520 if you are subject to an output-based standard, you must calculate the total gross or net energy output for the affected EGU’s compliance period by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)(5) of this section for all of the valid operating hours in the applicable compliance period. (ii) If you are subject to a heat inputbased standard, you must calculate the total heat input for each fuel fired during the compliance period. The calculation of total heat input for each individual fuel must include all valid operating hours and must also be consistent with any fuel-specific procedures specified within your PO 00000 Frm 00145 ADD-35 Sfmt 4700 Fmt 4701 Notification, Reports, and Records § 60.5550 What notifications must I submit and when? (a) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (3) and 60.19, as applicable to your affected EGU(s) (see Table 3 of this subpart). E:\FR\FM\23OCR2.SGM 23OCR2 ER23OC15.004 mstockstill on DSK4VPTVN1PROD with RULES2 Where: ER23OC15.003 procedures in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of affected EGU(s). For an operating hour in which a valid CO2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, if there is no gross or net electrical output, but there is mechanical or useful thermal output, you must still determine the gross or net energy output for that hour. In addition, USCA Case #15-1381 #1640985 Filed: Page 38 of 44 64654 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations (b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable, to your affected EGUs. mstockstill on DSK4VPTVN1PROD with RULES2 § 60.5555 when? What reports must I submit and (a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable. (1) For affected EGUs that are required by § 60.5525 to conduct initial and ongoing compliance determinations on a 12-operating-month rolling average basis, you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected EGU, you must submit a report for the calendar quarter that includes the twelfth operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report you must include the following information, as applicable: (i) Each rolling average CO2 mass emissions rate for which the last (twelfth) operating month in a 12operating-month compliance period falls within the calendar quarter. You must calculate each average CO2 mass emissions rate for the compliance period according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth operating months in each compliance period for which you performed a CO2 mass emissions rate calculation. If there are no compliance periods that end in the quarter, you must include a statement to that effect; (ii) If one or more compliance periods end in the quarter, you must identify each operating month in the calendar quarter where your EGU violated the applicable CO2 emission standard; (iii) If one or more compliance periods end in the quarter and there are no violations for the affected EGU, you must include a statement indicating this in the report; (iv) The percentage of valid operating hours in each 12-operating-month compliance period described in paragraph (a)(1)(i) of this section (i.e., the total number of valid operating hours (as defined in § 60.5540(a)(1)) in that period divided by the total number of operating hours in that period, multiplied by 100 percent); (v) Consistent with § 60.5520, the CO2 emissions standard (as identified in Table 1 or 2 of this part) with which your affected EGU must comply; and VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 (vi) Consistent with § 60.5520, an indication whether or not the hourly gross or net energy output (Pgross/net) values used in the compliance determinations are based solely upon gross electrical load. (3) In the final quarterly report of each calendar year, you must include the following: (i) Consistent with § 60.5520, gross energy output or net energy output sold to an electric grid, as applicable to the units of your emission standard, over the four quarters of the calendar year; and (ii) The potential electric output of the EGU. (b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA. (c)(1) For affected EGUs under this subpart that are also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter. (2) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart. (3)(i) For all newly-constructed affected EGUs under this subpart that are also subject to the Acid Rain Program, you must begin submitting the quarterly electronic emissions reports described in paragraph (c)(1) of this section in accordance with § 75.64(a) of this chapter, i.e., beginning with data recorded on and after the earlier of: (A) The date of provisional certification, as defined in § 75.20(a)(3) of this chapter; or (B) 180 days after the date on which the EGU commences commercial operation (as defined in § 72.2 of this chapter). (ii) For newly-constructed affected EGUs under this subpart that are not subject to the Acid Rain Program, you must begin submitting the quarterly electronic reports described in paragraph (c)(2) of this section, beginning with data recorded on and after: (A) The date on which reporting is required to begin under § 75.64(a) of this chapter, if that date occurs on or after October 23, 2015; or PO 00000 Frm 00146 ADD-36 Sfmt 4700 Fmt 4701 (B) October 23, 2015, if the date on which reporting would ordinarily be required to begin under § 75.64(a) of this chapter has passed prior to October 23, 2015. (iii) For reconstructed or modified units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net energy output data on that date. Otherwise, emissions data reporting shall be on a gross energy output basis until the date that the Client Tool is first able to receive and process net energy output data. (4) If any required monitoring system has not been provisionally certified by the applicable date on which emissions data reporting is required to begin under paragraph (c)(3) of this section, the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with § 75.4(j) of this chapter, § 75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operating hours in which CO2 mass emission rates are calculated using maximum potential values are not ‘‘valid operating hours’’ (as defined in § 60.5540(a)(1)), and shall not be used in the compliance determinations under § 60.5540. (d) For affected EGUs subject to the Acid Rain Program, the reports required under paragraphs (a) and (c)(1) of this section shall be submitted by: (1) The person appointed as the Designated Representative (DR) under § 72.20 of this chapter; or (2) The person appointed as the Alternate Designated Representative (ADR) under § 72.22 of this chapter; or (3) A person (or persons) authorized by the DR or ADR under § 72.26 of this chapter to make the required submissions. (e) For affected EGUs that are not subject to the Acid Rain Program, the owner or operator shall appoint a DR and (optionally) an ADR to submit the reports required under paragraphs (a) and (c)(2) of this section. The DR and ADR must register with the Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submissions to one or more persons. (f) If your affected EGU captures CO2 to meet the applicable emission limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and either: E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 39 of 44 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations 64655 (1) Report in accordance with the requirements of 40 CFR part 98, subpart RR, if injection occurs on-site, or (2) Transfer the captured CO2 to an EGU or facility that reports in accordance with the requirements of 40 CFR part 98, subpart RR, if injection occurs off-site. (3) Transfer the captured CO2 to a facility that has received an innovative technology waiver from EPA pursuant to paragraph (g) of this section. (g) Any person may request the Administrator to issue a waiver of the requirement that captured CO2 from an affected EGU be transferred to a facility reporting under 40 CFR part 98, subpart RR. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO2 as effectively as geologic sequestration, and that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO2, and permanence of the CO2 storage. The Administrator may test the system itself, or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology’s effectiveness, safety, and ability to store captured CO2 without release. The Administrator may grant conditional approval of a technology, with the approval conditioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of releases of CO2 or other pollutants. The Administrator will provide notice to the public of any application under this provision and provide public notice of any proposed action on a petition before the Administrator takes final action. mstockstill on DSK4VPTVN1PROD with RULES2 § 60.5560 What records must I maintain? (a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f). (b)(1) For affected EGUs subject to the Acid Rain Program, you must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (2) For affected EGUs that are not subject to the Acid Rain Program, you must also follow the recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter, to the extent that those records provide applicable data for the compliance determinations required VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 under this subpart. Regardless of the prior sentence, at a minimum, the following records must be kept, as applicable to the types of continuous monitoring systems used to demonstrate compliance under this subpart: (i) Monitoring plan records under § 75.53(g) and (h) of this chapter; (ii) Operating parameter records under § 75.57(b)(1) through (4) of this chapter; (iii) The records under § 75.57(c)(2) of this chapter, for stack gas volumetric flow rate; (iv) The records under § 75.57(c)(3) of this chapter for continuous moisture monitoring systems; (v) The records under § 75.57(e)(1) of this chapter, except for paragraph (e)(1)(x), for CO2 concentration monitoring systems or O2 monitors used to calculate CO2 concentration; (vi) The records under § 75.58(c)(1) of this chapter, specifically paragraphs (c)(1)(i), (ii), and (viii) through (xiv), for oil flow meters; (vii) The records under § 75.58(c)(4) of this chapter, specifically paragraphs (c)(4)(i), (ii), (iv), (v), and (vii) through (xi), for gas flow meters; (viii) The quality-assurance records under § 75.59(a) of this chapter, specifically paragraphs (a)(1) through (12) and (15), for CEMS; (ix) The quality-assurance records under § 75.59(a) of this chapter, specifically paragraphs (b)(1) through (4), for fuel flow meters; and (x) Records of data acquisition and handling system (DAHS) verification under § 75.59(e) of this chapter. (c) You must keep records of the calculations you performed to determine the hourly and total CO2 mass emissions (tons) for: (1) Each operating month (for all affected EGUs); and (2) Each compliance period, including, each 12-operating-month compliance period. (d) Consistent with § 60.5520, you must keep records of the applicable data recorded and calculations performed that you used to determine your affected EGU’s gross or net energy output for each operating month. (e) You must keep records of the calculations you performed to determine the percentage of valid CO2 mass emission rates in each compliance period. (f) You must keep records of the calculations you performed to assess compliance with each applicable CO2 mass emissions standard in Table 1 or 2 of this subpart. (g) You must keep records of the calculations you performed to determine any site-specific carbon- PO 00000 Frm 00147 ADD-37 Sfmt 4700 Fmt 4701 based F-factors you used in the emissions calculations (if applicable). § 60.5565 In what form and how long must I keep my records? (a) Your records must be in a form suitable and readily available for expeditious review. (b) You must maintain each record for 3 years after the date of conclusion of each compliance period. (c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. Records that are accessible from a central location by a computer or other means that instantly provide access at the site meet this requirement. You may maintain the records off site for the remaining year(s) as required by this subpart. Other Requirements and Information § 60.5570 What parts of the general provisions apply to my affected EGU? Notwithstanding any other provision of this chapter, certain parts of the general provisions in §§ 60.1 through 60.19, listed in Table 3 to this subpart, do not apply to your affected EGU. § 60.5575 Who implements and enforces this subpart? (a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency. (b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate. (1) Approval of alternatives to the emission standards. (2) Approval of major alternatives to test methods. (3) Approval of major alternatives to monitoring. (4) Approval of major alternatives to recordkeeping and reporting. (5) Performance test and data reduction waivers under § 60.8(b). E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 40 of 44 64656 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations mstockstill on DSK4VPTVN1PROD with RULES2 § 60.5580 subpart? What definitions apply to this As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (general provisions of this part). Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating. Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis, as determined by the physical design and characteristics of the EGU at ISO conditions. For a stationary combustion turbine, base load rating includes the heat input from duct burners. Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM International in ASTM D388–99 (Reapproved 2004) e1 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including, but not limited to, solventrefined coal, gasified coal (not meeting the definition of natural gas), coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart. Combined cycle unit means an electric generating unit that uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit (HRSG) to generate additional electricity. Combined heat and power unit or CHP unit, (also known as ‘‘cogeneration’’) means an electric generating unit that that use a steam generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy source. Design efficiency means the rated overall net efficiency (e.g., electric plus useful thermal output) on a lower heating value basis at the base load rating, at ISO conditions, and at the maximum useful thermal output (e.g., CHP unit with condensing steam turbines would determine the design efficiency at the maximum level of extraction and/or bypass). Design efficiency shall be determined using one of the following methods: ASME PTC 22 Gas Turbines (incorporated by reference, see § 60.17), ASME PTC 46 Overall Plant Performance (incorporated by reference, see § 60.17) or ISO 2314 Gas turbines—acceptance tests (incorporated by reference, see § 60.17). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by ASTM International in ASTM D396–98 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by ASTM International in ASTM D975–08a (incorporated by reference, see § 60.17); kerosene, as defined by ASTM International in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by ASTM International in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by ASTM International in ASTM D7467 (incorporated by reference, see § 60.17). Electric Generating units or EGU means any steam generating unit, IGCC unit, or stationary combustion turbine that is subject to this rule (i.e., meets the applicability criteria) Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, cokeoven gas, synthetic gas, and gasified coal. Gross energy output means: (1) For stationary combustion turbines and IGCC, the gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output. (2) For steam generating units, the gross electric or mechanical output from the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output; (3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operating-month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output. PO 00000 Frm 00148 ADD-38 Sfmt 4700 Fmt 4701 Heat recovery steam generating unit (HRSG) means an EGU in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Integrated gasification combined cycle facility or IGCC means a combined cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas, plus any integrated equipment that provides electricity or useful thermal output to the affected EGU or auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the EGU during operation. ISO conditions means 288 Kelvin (15°C), 60 percent relative humidity and 101.3 kilopascals pressure. Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual oil. Mechanical output means the useful mechanical energy that is not used to operate the affected EGU(s), generate electricity and/or thermal energy, or to enhance the performance of the affected EGU. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. Finally, natural gas does not include the following gaseous fuels: Landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable CO2 content or heating value. Net-electric sales means: (1) The gross electric sales to the utility power distribution system minus purchased power; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on an annual basis, the gross electric sales to the utility power E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 USCA Case #15-1381 #1640985 Filed: Page 41 of 44 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations 64657 distribution system minus purchased power of the thermal host facility or facilities. (3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales. (4) Electric sales that that result from a system emergency are not included when calculating net-electric sales. Net-electric output means the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means: (1) The net electric or mechanical output from the affected EGU plus 100 percent of the useful thermal output; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12operating-month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output. Operating month means a calendar month during which any fuel is combusted in the affected EGU at any time. Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Potential electric output means 33 percent or the base load rating design efficiency at the maximum electric production rate (e.g., CHP units with condensing steam turbines will operate at maximum electric production), whichever is greater, multiplied by the base load rating (expressed in MMBtu/ h) of the EGU, multiplied by 106 Btu/ MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient affected EGU with a 100 MW (341 MMBtu/h) fossil fuel heat input capacity would have a 306,000 MWh 12-month potential electric output capacity). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 °C, 77 °F) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Stationary combustion turbine means all equipment including, but not limited to, the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. A stationary combustion turbine that burns any solid fuel directly is considered a steam generating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment. System emergency means any abnormal system condition that the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator determines requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore call for maximum generation resources to operate in the affected area, or for the specific affected EGU to operate to avert loss of load. Useful thermal output means the thermal energy made available for use in PO 00000 Frm 00149 ADD-39 Sfmt 4700 Fmt 4701 any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output), or to supply energy to a pollution control device at the affected EGU. Useful thermal output for affected EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s)) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. Valid data means quality-assured data generated by continuous monitoring systems that are installed, operated, and maintained according to part 75 of this chapter. For CEMS, the initial certification requirements in § 75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality-assured data are reported under this subpart; for on-going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before qualityassured data are reported under this subpart (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D to part 75), and for on-going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 apply (except for qualifying commercial billing meters). Violation means a specified averaging period over which the CO2 emissions rate is higher than the applicable emissions standard located in Table 1 or 2 of this subpart. E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 42 of 44 64658 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations TABLE 1 OF SUBPART TTTT OF PART 60—CO2 EMISSION STANDARDS FOR AFFECTED STEAM GENERATING UNITS AND INTEGRATED GASIFICATION COMBINED CYCLE FACILITIES THAT COMMENCED CONSTRUCTION AFTER JANUARY 8, 2014 AND RECONSTRUCTION OR MODIFICATION AFTER JUNE 18, 2014 [Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 2 significant figures] CO2 Emission standard Affected EGU Newly constructed steam generating unit or integrated gasification combined cycle (IGCC). Reconstructed steam generating unit or IGCC that has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less. Reconstructed steam generating unit or IGCC that has a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h). Modified steam generating unit or IGCC ................................................. 640 kg CO2/MWh of gross energy output (1,400 lb CO2/MWh). 910 kg of CO2 per MWh of gross energy output (2,000 lb CO2/MWh). 820 kg of CO2 per MWh of gross energy output (1,800 lb CO2/MWh). A unit-specific emission limit determined by the unit’s best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission limit will be no lower than: 1. 1,800 lb CO2/MWh-gross for units with a base load rating greater than 2,000 MMBtu/h; or 2. 2,000 lb CO2/MWh-gross for units with a base load rating of 2,000 MMBtu/h or less. TABLE 2 OF SUBPART TTTT OF PART 60—CO2 EMISSION STANDARDS FOR AFFECTED STATIONARY COMBUSTION TURBINES THAT COMMENCED CONSTRUCTION AFTER JANUARY 8, 2014 AND RECONSTRUCTION AFTER JUNE 18, 2014 (NET ENERGY OUTPUT-BASED STANDARDS APPLICABLE AS APPROVED BY THE ADMINISTRATOR) [Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 2 significant figures] Affected EGU CO2 Emission standard Newly constructed or reconstructed stationary combustion turbine that supplies more than its design efficiency or 50 percent, whichever is less, times its potential electric output as net-electric sales on both a 12-operating month and a 3-year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operatingmonth rolling average basis. Newly constructed or reconstructed stationary combustion turbine that supplies its design efficiency or 50 percent, whichever is less, times its potential electric output or less as net-electric sales on either a 12-operating month or a 3-year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operatingmonth rolling average basis. Newly constructed and reconstructed stationary combustion turbine that combusts 90% or less natural gas on a heat input basis on a 12-operating-month rolling average basis. 450 kg of CO2 per MWh of gross energy output (1,000 lb CO2/MWh); or 470 kilograms (kg) of CO2 per megawatt-hour (MWh) of net energy output (1,030 lb/MWh). 50 kg CO2 per gigajoule (GJ) of heat input (120 lb CO2/MMBtu). 50 kg CO2/GJ of heat input (120 lb/MMBtu) to 69 kg CO2/GJ of heat input (160 lb/MMBtu) as determined by the procedures in § 60.5525. TABLE 3 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A OF PART 60 (GENERAL PROVISIONS) TO SUBPART TTTT General provisions citation Subject of citation Applies to subpart TTTT ............ ............ ............ ............ Applicability ................................................................ Definitions .................................................................. Units and Abbreviations ............................................. Address ...................................................................... Yes. Yes ....................... Yes. Yes ....................... § 60.5 ............ § 60.6 ............ § 60.7 ............ Determination of construction or modification ........... Review of plans ......................................................... Notification and Recordkeeping ................................. Yes. Yes. Yes ....................... § 60.8 ............ § 60.9 ............ § 60.10 .......... § 60.11 .......... Performance tests ...................................................... Availability of Information ........................................... State authority ............................................................ Compliance with standards and maintenance requirements. Circumvention ............................................................ Monitoring requirements ............................................ No. Yes. Yes. No. mstockstill on DSK4VPTVN1PROD with RULES2 § 60.1 § 60.2 § 60.3 § 60.4 § 60.12 .......... § 60.13 .......... VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00150 Yes. No ........................ ADD-40 Sfmt 4700 Fmt 4701 Explanation Additional terms defined in § 60.5580. Does not apply to information reported electronically through ECMPS. Duplicate submittals are not required. Only the requirements to submit the notifications in § 60.7(a)(1) and (3) and to keep records of malfunctions in § 60.7(b), if applicable. All monitoring is done according to part 75. E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 43 of 44 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations 64659 TABLE 3 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A OF PART 60 (GENERAL PROVISIONS) TO SUBPART TTTT—Continued General provisions citation Subject of citation Applies to subpart TTTT § 60.14 .......... Modification ................................................................ § 60.15 § 60.16 § 60.17 § 60.18 § 60.19 Reconstruction ........................................................... Priority list .................................................................. Incorporations by reference ....................................... General control device requirements ......................... General notification and reporting requirements ....... Yes (steam generating units and IGCC facilities). No (stationary combustion turbines. Yes. No. Yes. No. Yes ....................... .......... .......... .......... .......... .......... PART 70—STATE OPERATING PERMIT PROGRAMS 4. The authority citation for part 70 continues to read as follows: ■ Authority: 42 U.S.C. 7401, et seq. 5. In § 70.2, the definition of ‘‘Regulated pollutant (for presumptive fee calculation)’’ is amended by: ■ a. Revising the introductory text; ■ b. Removing ‘‘or’’ from the end of paragraph (2); ■ c. Removing the period at the end of paragraph (3) and adding ‘‘; or’’ in its place; and ■ d. Adding paragraph (4). The revision and additions read as follows: ■ § 70.2 Activity * * * * Regulated pollutant (for presumptive fee calculation), which is used only for purposes of § 70.9(b)(2), means any regulated air pollutant except the following: * * * * * (4) Greenhouse gases. * * * * * ■ 6. Section 70.9 is amended by revising paragraph (b)(2)(i), and adding paragraph (b)(2)(v) to read as follows: § 70.9 Fee determination and certification. mstockstill on DSK4VPTVN1PROD with RULES2 * * * * * (b) * * * (2)(i) The Administrator will presume that the fee schedule meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and any VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 Does not apply to notifications under § 75.61 or to information reported through ECMPS. GHG cost adjustment required under paragraph (b)(2)(v) of this section. * * * * * (v) GHG cost adjustment. The amount calculated in paragraph (b)(2)(i) of this section shall be increased by the GHG cost adjustment determined as follows: For each activity identified in the following table, multiply the number of activities performed by the permitting authority by the burden hours per activity, and then calculate a total number of burden hours for all activities. Next, multiply the burden hours by the average cost of staff time, including wages, employee benefits and overhead. Definitions. * Explanation Burden hours per activity The revisions and additions read as follows: § 71.2 Definitions. * * * * * Regulated pollutant (for fee calculation), which is used only for purposes of § 71.9(c), means any ‘‘regulated air pollutant’’ except the following: * * * * * (4) Greenhouse gases. * * * * * ■ 9. Section 71.9 is amended by: ■ a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4); and ■ b. Adding paragraph (c)(8). The revisions and addition read as follows: § 71.9 Permit fees. * * * * (c) * * * GHG completeness determina(1) For part 71 programs that are tion (for initial permit or upadministered by EPA, each part 71 dated application) .................... 43 source shall pay an annual fee which is GHG evaluation for a permit the sum of: modification or related permit (i) $32 per ton (as adjusted pursuant action ....................................... 7 GHG evaluation at permit reto the criteria set forth in paragraph newal ....................................... 10 (n)(1) of this section) times the total tons of the actual emissions of each regulated * * * * * pollutant (for fee calculation) emitted from the source, including fugitive PART 71—FEDERAL OPERATING emissions; and PERMIT PROGRAMS (ii) Any GHG fee adjustment required under paragraph (c)(8) of this section. ■ 7. The authority citation for part 71 (2) * * * continues to read as follows: (i) Where the EPA has not suspended Authority: 42 U.S.C. 7401, et seq. its part 71 fee collection pursuant to paragraph (c)(2)(ii) of this section, the ■ 8. In § 71.2, the definition of annual fee for each part 71 source shall ‘‘Regulated pollutant (for fee be the sum of: calculation)’’ is amended by: (A) $24 per ton (as adjusted pursuant ■ a. Removing ‘‘or’’ from the end of to the criteria set forth in paragraph paragraph (2); (n)(1) of this section) times the total tons ■ b. Removing the period at the end of of the actual emissions of each regulated paragraph (3) and adding ‘‘; or’’ in its pollutant (for fee calculation) emitted place; and from the source, including fugitive ■ b. Adding paragraph (4). emissions; and PO 00000 Frm 00151 ADD-41 Sfmt 4700 Fmt 4701 * E:\FR\FM\23OCR2.SGM 23OCR2 USCA Case #15-1381 #1640985 Filed: Page 44 of 44 64660 Federal Register / Vol.Document 80, No. 205 / Friday, October 23, 201510/13/2016 / Rules and Regulations mstockstill on DSK4VPTVN1PROD with RULES2 (B) Any GHG fee adjustment required under paragraph (c)(8) of this section. * * * * * (3) For part 71 programs that are administered by EPA with contractor assistance, the per ton fee shall vary depending on the extent of contractor involvement and the cost to EPA of contractor assistance. The EPA shall establish a per ton fee that is based on the contractor costs for the specific part 71 program that is being administered, using the following formula: Cost per ton = (E × 32) + [(1 ¥ E) × $C] Where E represents EPA’s proportion of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1 ¥ E represents the contractor’s effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed by using the following formula: C = [ B + T + N] divided by 12,300,000 Where B represents the base cost (contractor costs), where T represents travel costs, and where N represents nonpersonnel data management and tracking costs. In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section. (4) For programs that are delegated in part, the fee shall be computed using the following formula: Cost per ton = (E × 32) + (D × 24) + [(1 ¥ E ¥ D) × $C] Where E and D represent, respectively, the EPA and delegate VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 agency proportions of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1 ¥ E ¥ D represents the contractor’s effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed using the formula for contractor assistance cost found in paragraph (c)(3) of this section and shall be zero if contractor assistance is not utilized. In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section. * * * * * (8) GHG fee adjustment. The annual fee shall be increased by a GHG fee adjustment for any source that has initiated an activity listed in the following table since the fee was last paid. The GHG fee adjustment shall be equal to the set fee provided in the table for each activity that has been initiated since the fee was last paid: Activity Set fee GHG completeness determination (for initial permit or updated application) .................... GHG evaluation for a permit modification or related permit action ....................................... GHG evaluation at permit renewal ....................................... * PO 00000 * * * * $2,236 PART 98—MANDATORY GREENHOUSE GAS REPORTING 10. The authority citation for part 98 is revised to read as follows: ■ Authority: 42 U.S.C. 7401–7671q. 11. Section 98.426 is amended by adding paragraph (h) to read as follows: ■ § 98.426 Data reporting requirements. * * * * * (h) If you capture a CO2 stream from an electricity generating unit that is subject to subpart D of this part and transfer CO2 to any facilities that are subject to subpart RR of this part, you must: (1) Report the facility identification number associated with the annual GHG report for the subpart D facility; (2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to which CO2 is transferred; and (3) Report the annual quantity of CO2 in metric tons that is transferred to each subpart RR facility. ■ 12. Section 98.427 is amended by adding paragraph (d) to read as follows: § 98.427 Records that must be retained. * * * * * (d) Facilities subject to § 98.426(h) 364 must retain records of CO2 in metric 520 tons that is transferred to each subpart RR facility. [FR Doc. 2015–22837 Filed 10–22–15; 8:45 am] BILLING CODE 6560–50–P Frm 00152 ADD-42 Sfmt 9990 Fmt 4701 E:\FR\FM\23OCR2.SGM 23OCR2 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 1 Case No. 15-3751 (and related cases: 15-3799; 15-3817; 15-3820; 15-3822; 153823; 15-3831; 15-3837; 15-3839; 15-3850; 15-3853; 15-3858; 15-3885; 15-3887; 15-3948; 15-4159; 15-4162; 15-4188; 15-4211; 15-4234; 15-4305; 15-4404) IN THE UNITED STATES COURT OF APPEALS FOR THE SIXTH CIRCUIT MURRAY ENERGY CORPORATION, et al., Petitioners, v. U.S. ENVIRONMENTAL PROTECTION AGENCY, et al., Respondents. ) ) ) ) ) ) ) ) ) ) ) ) ) In Re: Environmental Protection Agency and Department of Defense, Final Rule: Clean Water Rule: Definition of “Waters of the United States,” 80 Fed. Reg. 37,054, published June 29, 2015 (MCP No. 135) On petition for review from the Environmental Protection Agency and the U.S. Army Corps of Engineers OPENING BRIEF OF STATE PETITIONERS Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record Peter T. Reed Deputy Solicitor Date: November 1, 2016 Office of the Attorney General 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ ohioattorneygeneral.gov Counsel for Petitioner State of Ohio Additional counsel listed at end Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 2 TABLE OF CONTENTS TABLE OF CONTENTS ........................................................................................... i  TABLE OF AUTHORITIES ................................................................................... iii  STATEMENT IN SUPPORT OF ORAL ARGUMENT ........................................ ix JURISDICTIONAL STATEMENT ..........................................................................1  INTRODUCTION .....................................................................................................1  ISSUES PRESENTED...............................................................................................5  STATEMENT OF THE CASE ..................................................................................5  A. Statutory Background ...............................................................................5  B.   Supreme Court Precedent.........................................................................7  C.  The Proposed Rule ....................................................................................9  D.  The Final Rule ........................................................................................11  E.    This Litigation ........................................................................................14  SUMMARY OF ARGUMENT ...............................................................................15  ARGUMENT ...........................................................................................................20  I.  THE RULE VIOLATES THE CLEAN WATER ACT..............................20  A. The Rule Fails Justice Kennedy’s Significant Nexus Test. ...................22  B.  The Rule Fails The Rapanos Plurality’s Test. .......................................34  C.  The Rule Is Not Clearly Authorized By The CWA. ..............................37  II.  THE RULE VIOLATES THE ADMINISTRATIVE PROCEDURE ACT. ............................................................................................................43  A. The Agencies Built The Final Rule Around Distance-Based Components And An Unduly Narrow Exclusion That Were Never Submitted For Public Notice-And-Comment. ............................45  B.  The Distance-Based Components And Unduly Narrow Exclusion Are Unsupported By The Record. .........................................................52  i Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 3 C.  The Rule’s Expansive Interpretation Of “Significant Nexus” Is Arbitrary And Capricious. .....................................................................55  III.    THE RULE VIOLATES THE CONSTITUTION.......................................57  A. The Rule Violates The States’ Tenth Amendment Rights. ....................57  B.   The Rule Exceeds Congress’s Commerce Clause Authority. ...............64  C.   The Rule Is Unconstitutionally Vague. ..................................................71  D. The Agencies’ Repeated Unlawful Interpretations Of “Waters Of The United States” Threaten The Constitutionality Of That Term. ......75  IV.  THE RULE VIOLATES THE NATIONAL ENVIRONMENTAL POLICY ACT..............................................................................................77  A.   The Corps Failed To Prepare An Environmental Impact Statement. ...78  B.  The Corps Rejected The Need For An Environmental Impact Statement Based On A Flawed Environmental Assessment. ...................  C.  The Corps Failed To Consider A Reasonable Range Of Alternatives. ..........................................................................................86  CONCLUSION ........................................................................................................90  ii Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 4 TABLE OF AUTHORITIES Federal Cases Allina Health Servs. v. Sebelius, 746 F.3d 1102 (D.C. Cir. 2014)............................................................................46 Am. Radio Relay League, Inc. v. F.C.C., 524 F.3d 227 (D.C. Cir. 2008)....................................................................... 87, 90 Amerijet Int’l, Inc. v. Pistole, 753 F.3d 1343 (D.C. Cir. 2014)............................................................... 52, 53, 54 Ass’n of Cleveland Fire Fighters v. City of Cleveland, 502 F.3d 545 (6th Cir. 2007) ......................................................................... 19, 71 Ass’n of Private Sector Colls. & Univs. v. Duncan, 681 F.3d 427 (D.C. Cir. 2012)..............................................................................48 BFP v. Resolution Trust Corp., 511 U.S. 531 (1994) .............................................................................................38 Bond v. United States, 134 S. Ct. 2077 (2014) .................................................................................. 37, 38 Bond v. United States, 564 U.S. 211 (2011) .............................................................................................58 Bowman Transp., Inc. v. Arkansas-Best Freight Sys., Inc., 419 U.S. 281 (1974) ...................................................................................... 57, 81 Charter Twp. of Huron, Mich. v. Richards, 997 F.2d 1168 (6th Cir. 1993) ................................................................. 78, 84, 87 Chevron, U.S.A., Inc. v. Natural Res. Def. Council, 467 U.S. 837 (1984) .............................................................................................38 Chicago v. Morales, 527 U.S. 41 (1999) .................................................................................. 71, 72, 74 Connally v. Gen. Constr. Co., 269 U.S. 385 (1926) .............................................................................................71 Crounse Corp. v. I.C.C., 781 F.2d 1176 (6th Cir. 1986) ....................................................................... 78, 84 CSX Transp., Inc. v. Surface Transp. Bd., 584 F.3d 1076 (D.C. Cir. 2009)......................................................... 46, 50, 51, 52 iii Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 5 Edward J. DeBartolo Corp. v. Fla. Gulf Coast Bldg. & Constr. Trades Council, 485 U.S. 568 (1988) ...............................................................................37 EEOC v. Arabian Am. Oil Co., 499 U.S. 244 (1991) .............................................................................................37 Envtl. Integrity Project v. EPA, 425 F.3d 992 (D.C. Cir. 2005)....................................................................... 46, 49 FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120 (2000) .............................................................................................41 FERC v. Mississippi, 456 U.S. 742 (1982) .............................................................................................58 Friends of Tims Ford v. Tennessee Valley Auth., 585 F.3d 955 (6th Cir. 2009) ................................................................................77 Gibbons v. Ogden, 22 U.S. (9 Wheat.) 1 (1824) .................................................................................65 Gonzales v. Raich, 125 S. Ct. 2195 (2005) .........................................................................................67 Gregory v. Ashcroft, 501 U.S. 452 (1991) .............................................................................................38 Hodel v. Va. Surface Mining & Reclamation Ass’n, Inc., 452 U.S. 264 (1981) ................................................................................ 58, 60, 63 Hodges v. Abraham, 300 F.3d 432 (4th Cir. 2002) ................................................................................79 In re EPA, 803 F.3d 804 (6th Cir. 2015) ......................................................................... 15, 84 In re U.S. Dep’t of Defense and U.S. EPA Final Rule, 817 F.3d 261 (6th Cir. 2016) ..................................................................... 1, 15, 79 Indep. Petroleum Ass’n of Am. v. Babbitt, 92 F.3d 1248 (D.C. Cir. 1996)....................................................................... 52, 55 Int’l Union, UMWA v. MSHA, 407 F.3d 1250 (D.C. Cir. 2005)......................................................... 44, 45, 46, 48 Johnson v. United States, 135 S. Ct. 2556 (2015) ...................................................................... 71, 75, 76, 77 Kaiser Aetna v. United States, 444 U.S. 164 (1979) .............................................................................................65 iv Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 6 Kentucky Waterways Alliance v. Johnson, 540 F.3d 466 (6th Cir. 2008) ................................................................................52 Klamath-Siskiyou Wildlands Ctr. v. Bureau of Land Mgmt., 387 F.3d 989 (9th Cir. 2004) ................................................................... 84, 85, 86 Kolender v. Lawson, 461 U.S. 352 (1983) .............................................................................................74 Latin Ams. for Soc. & Econ. Dev. v. Adm’r of the Fed. Highway Admin., 756 F.3d 447 (6th Cir. 2014) ................................................................................43 Long Island Care at Home, Ltd. v. Coke, 551 U.S. 158 (2007) ...................................................................................... 44, 45 Marks v. United States, 430 U.S. 188 (1977) .............................................................................................21 Middle Rio Grande Conservancy Dist. v. Norton, 294 F.3d 1220 (10th Cir. 2002) ............................................................................83 Motor Vehicle Mfrs. Ass’n of United States, Inc. v. State Farm Mut. Ins. Co., 463 U.S. 29 (1983) ............................................................................ 52, 54, 79, 82 Nat’l Welfare Rights Org. v. Mathews, 533 F.2d 637 (D.C. Cir. 1976)................................................................. 52, 53, 54 North Dakota v. U.S. EPA, 127 F. Supp. 3d 1047 (D.N.D. 2015) ...................................................................84 Ohio Dep’t of Human Servs. v. U.S. Dep’t of Health & Human Servs., 862 F.2d 1228 (6th Cir. 1988) ..............................................................................44 Oklahoma ex rel. Phillips v. Guy F. Atkinson Co., 313 U.S. 508 (1941) .............................................................................................66 Pac. Legal Found. v. Andrus, 657 F.2d 829 (6th Cir. 1981) ................................................................................77 Partners in Forestry Co-op., Northwood Alliance, Inc. v. U.S. Forest Serv., 638 F. App’x 456 (6th Cir. 2015) .................................................................. 78, 87 Phillips Petroleum Co. v. Johnson, 22 F.3d 616 (5th Cir. 1994) ........................................................................... 45, 48 Rapanos v. United States, 547 U.S. 715 (2006) ..................................................................................... passim Sackett v. EPA, 132 S. Ct. 1367 (2012) .................................................................................. 30, 76 v Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 7 Save Our Cumberland Mountains v. Kempthorne, 453 F.3d 334 (6th Cir. 2006) ................................................................................88 SEC v. Chenery Corp., 318 U.S. 80 (1943) ........................................................................................ 21, 34 Shell Oil Co. v. EPA, 950 F.2d 741 (D.C. Cir. 1991)................................................................. 46, 48, 50 Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506 (D.C. Cir. 1983)............................................... 45, 46, 47, 49, 50, 51 Solid Waste Agency of N. Cook Cnty. v. U.S. Army Corps of Eng’rs, 531 U.S. 159 (2001) ..................................................................................... passim Summit Petroleum Corp. v. U.S. EPA, 690 F.3d 733 (6th Cir. 2012) ................................................................................30 Tennessee v. FCC, 832 F.3d 597 (6th Cir. 2016) ................................................................................38 U.S. Army Corps of Eng’rs v. Hawkes, Co., 136 S. Ct. 1807 (2016) ...................................................................... 42, 75, 76, 83 United States v. Appalachian Power Co., 311 U.S. 377 (1940) ...........................................................................................8, 9 United States v. Bass, 404 U.S. 336 (1971) .............................................................................................38 United States v. Cundiff, 555 F.3d 200 (6th Cir. 2009) ................................................................................21 United States v. Lopez, 514 U.S. 549 (1995) .............................................................. 65, 66, 67, 68, 69, 70 United States v. Morrison, 529 U.S. 598 (2000) ................................................................................ 67, 68, 70 United States v. Riverside Bayview Homes, Inc., 474 U.S. 121 (1985) .............................................................................................30 Util. Air Regulatory Grp. v. EPA, 134 S. Ct. 2427 (2014) .................................................................................. 37, 41 Federal Statutes 5 U.S.C. § 553 ................................................................................................... 43, 45 5 U.S.C. § 706 ..........................................................................................................52 vi Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 8 18 U.S.C. § 924 ........................................................................................................75 28 U.S.C. § 2112 ......................................................................................................14 33 U.S.C. § 1251 ........................................................................... 2, 5, 18, 39, 40, 58 33 U.S.C. § 1313 ................................................................................................. 6, 60 33 U.S.C. § 1319 ......................................................................................................71 33 U.S.C. § 1342 ................................................................................................. 6, 60 33 U.S.C. § 1344 ................................................................................................. 6, 60 33 U.S.C. § 1362 ....................................................................................... 2, 6, 20, 65 33 U.S.C. § 1369 ................................................................................................. 1, 15 33 U.S.C. § 1371 ......................................................................................................77 42 U.S.C. § 4332 ......................................................................................... 11, 77, 87 State Statutes Ark. Code Ann. §§ 8-4-101 et seq. ..................................................................... 7, 64 Ky. Rev. Stat. §§ 224.70-100 et seq. .................................................................. 7, 64 Mo. Rev. Stat. §§ 644.006 et seq. ....................................................................... 7, 64 Mont. Code Ann. §§ 75-5-101 et seq.................................................................. 7, 64 N.D. Cent. Code §§ 61-28-01 et seq. .................................................................. 7, 64 N.M. Stat. Ann. §§ 74-6-4 et seq. ....................................................................... 7, 64 Tex. Water Code §§ 26.001 et seq. ..................................................................... 7, 64 Federal Constitution U.S. Const. art. I, § 8, cl. 3 .......................................................................................65 U.S. Const., amend. X..............................................................................................58 Regulations 33 C.F.R. Part 328 ....................................................................................................12 33 C.F.R. § 320.4(a).......................................................................................... 60, 69 33 C.F.R. § 328.3(a)(2) ............................................................................................34 33 C.F.R. § 328.3(a)(5) ............................................................................................12 33 C.F.R. § 328.3(a)(6) ............................................................................................12 33 C.F.R. § 328.3(a)(8) ............................................................. 13, 14, 31, 50, 53, 73 33 C.F.R. § 328.3(b) ................................................................................................61 vii Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 9 33 C.F.R. § 328.3(c)(1) ......................................................................... 12, 13, 51, 51 33 C.F.R. § 328.3(c)(2) ............................................................. 13, 28, 31, 36, 47, 53 33 C.F.R. § 328.3(c)(2)(ii) .......................................................................... 29, 35, 62 33 C.F.R. § 328.3(c)(3) ................................................................... 23, 24, 69, 70, 72 33 C.F.R. § 328.3(c)(5) ............................................................. 14, 31, 32, 36, 73, 74 33 C.F.R. § 328.3(c)(5)(vii) .....................................................................................70 33 C.F.R. § 328.3(c)(5)(viii) ....................................................................................70 33 C.F.R. § 328.3(c)(6) ............................................................................................24 33 C.F.R. § 328.3(e) (2005) .....................................................................................25 40 C.F.R. § 233.70 .....................................................................................................6 40 C.F.R. § 233.71 .....................................................................................................6 40 C.F.R. § 1501.6 ...................................................................................................86 40 C.F.R. § 1502.4(b) ..............................................................................................77 40 C.F.R. § 1507.1 ...................................................................................................77 40 C.F.R. § 1508.27 .................................................................................................78 40 C.F.R. § 1508.27(a).............................................................................................79 40 C.F.R. § 1508.27(b) ............................................................................................82 40 C.F.R. § 1508.27(b)(4) ........................................................................................83 40 C.F.R. § 1508.27(b)(6) ........................................................................................83 40 C.F.R. § 1508.28(b)(10) ......................................................................................84 40 C.F.R. § 1508.5 ...................................................................................................86 40 C.F.R. § 1508.9 ...................................................................................... 78, 84, 87 Federal Register 79 Fed. Reg. 22,188 (Apr. 21, 2014) .......................................................... 48, 50, 51 79 Fed. Reg. 61,590 (Oct. 14, 2014)........................................................................11 80 Fed. Reg. 2,100 (Jan. 15, 2015) ..........................................................................11 80 Fed. Reg. 37,054 (June 29, 2015) .... 4, 12, 14, 17, 23, 24, 27, 31, 32, 35, 42, 53, ............................................................................................... 54, 55, 72, 74, 79, 83 Other Authority S. Rep. No. 752, 79th Cong., 1st Sess. 14 (1945)....................................................44 viii Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 10 STATEMENT IN SUPPORT OF ORAL ARGUMENT The thirty-one State Petitioners request oral argument to address the significant legal defects identified herein. ix Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 11 JURISDICTIONAL STATEMENT The U.S. Environmental Protection Agency (“EPA”) and the U.S. Army Corps of Engineers (“Corps”) (collectively, “Agencies”) promulgated the Clean Water Rule on June 29, 2015. See Clean Water Rule: Definition of “Waters of the United States,” 80 Fed. Reg. 37,054-37,105 (June 29, 2015) (“Final Rule” or “Rule”). The States filed timely petitions for review within 120 days, as required under 33 U.S.C. § 1369(B)(1). This Court held that it has jurisdiction over the State petitions under 33 U.S.C. § 1369(B)(1)(F). See In re U.S. Dep’t of Defense and U.S. EPA Final Rule, 817 F.3d 261, 273 (6th Cir. 2016). The States have standing because the Rule’s expansion of the Agencies’ authority under the Clean Water Act (“CWA”) imposes significant and sovereign harm upon them. See, e.g., State Petitioners’ Motion for Stay Pending Review & Declarations, No. 15-3799, Dkt. 24, at 15-19 (filed Sept. 9, 2015). INTRODUCTION This case is about who has authority to regulate isolated land and water features that are far removed from any navigable waterway: the federal government or the sovereign States. The CWA, like the United States Constitution, reserves that authority to the States. Yet, in the Rule at issue here, the Agencies have asserted federal authority over many of those local resources. 1 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 12 When Congress enacted the CWA over forty years ago, it “chose to ‘recognize, preserve, and protect the primary responsibilities and rights of States . . . to plan the development and use . . . of land and water resources.’” Solid Waste Agency of N. Cook Cnty. v. U.S. Army Corps of Eng’rs, 531 U.S. 159, 174 (2001) (“SWANCC”) (quoting 33 U.S.C. § 1251(b)). But it granted to the federal government primary jurisdiction over the nation’s “navigable waters,” defined as “waters of the United States.” 33 U.S.C. § 1362(7). The resulting statutory regime balances traditional state authority over land use and water resources within their borders with the need for uniform federal regulation to protect navigable-in-fact waters. The Agencies have repeatedly sought to undermine this balance, asserting regulatory control over land and water resources far removed from the nation’s navigable-in-fact waters. Twice in the last fifteen years, the Supreme Court has rebuked the Agencies for their overreach. In SWANCC, the Court invalidated a federal rule that asserted jurisdiction over isolated, local ponds because the ponds were used by migratory birds. 531 U.S. at 174. Then, in Rapanos v. United States, 547 U.S. 715 (2006), the Court held that the Agencies could not regulate wetlands far removed from navigable-in-fact waters, including those wetlands adjacent to ditches and drains that the Agencies deemed tributaries of navigable waters. Id. at 742 (Scalia, J., plurality). In both SWANCC and Rapanos, the Court made clear 2 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 13 that, in order to preserve the federal-state regulatory balance, the statutory term “waters of the United States” must be given a meaning that is consistent with the primary purpose of the CWA—to protect navigable-in-fact waters. As the Court explained, “[t]he term ‘navigable’ has at least the import of showing us what Congress had in mind as its authority for enacting the CWA: its traditional jurisdiction over waters that were or had been navigable in fact or which could reasonably be so made.” SWANCC, 531 U.S. at 172; see also Rapanos, 547 U.S. at 778 (Kennedy, J., concurring in the judgment) (a “central requirement” of the Act is that “the word ‘navigable’ in ‘navigable waters’ be given some importance”). The Final Rule demonstrates that the Agencies have ignored the lessons of SWANCC and Rapanos. The Agencies now assert jurisdiction over the very same waters that the Supreme Court specifically held in those cases were outside the Agencies’ authority. But that is just the tip of the iceberg, as the Rule’s scope far exceeds what the Agencies sought to do in SWANCC and Rapanos. The Rule categorically federalizes stream beds that usually carry no water, and features that are connected to navigable-in-fact waters, if at all, only once a century. It reaches dry arroyos in New Mexico, ephemeral drainages in Wyoming, swales in Ohio farmland, isolated prairie potholes on the North Dakota plains, and thousands of square miles of Alaskan land that is frozen most of the year. The Rule destroys the 3 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 14 careful balance between federal and state authority that Congress struck in the CWA and that the Constitution mandates. The Rule is also a textbook example of procedural failure. The Agencies finalized a rule that looks nothing like the version submitted for public comment, all while declaring that the “rule does not have federalism implications,” 80 Fed. Reg. at 37,102. The Corps determined that the Rule would not have significant environmental or socioeconomic implications, ignoring its obligations under the National Environmental Policy Act (“NEPA”). These deficiencies, coupled with the sheer magnitude of the federal regulation at issue, make the Rule one of the most significant procedural failures in the history of the Administrative Procedure Act (“APA”). Finally, it is worth noting that for decades, the regulatory definition of the foundational term “waters of the United States” in the CWA has been named after the term it defines. But in an attempt to sell the country on an expansive new federal regulation, the Agencies coined a new term for their regulatory program— the “Clean Water Rule.” This terminology implies that without this Rule, the nation’s waters will be “unclean.” The thirty-one States challenging the Rule take deep exception to that implication. All of the States have robust regulatory programs that protect and preserve the natural resources within their boundaries. 4 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 15 ISSUES PRESENTED 1. May the Agencies violate the CWA by asserting federal authority over isolated local land and water resources? 2. May the Agencies define the statutory term “waters of the United States” based on central criteria they did not make available for public comment and that are not supported by the administrative record? 3. May the Agencies violate the Constitution by adopting a rule that (i) deprives the States of their Tenth Amendment rights, (ii) allows the Agencies to exercise power beyond the limits of the Commerce Clause, and (iii) is so vague that it prohibits ordinary people from understanding the CWA’s jurisdictional reach? 4. May the Corps violate NEPA by promulgating a major federal rule without preparing an environmental impact statement? STATEMENT OF THE CASE A. Statutory Background The CWA provides that “[i]t is the policy of the Congress to recognize, preserve, and protect the primary responsibilities and rights of States . . . to plan the development and use . . . of land and water resources.” 33 U.S.C. §1251(b). Congress granted the Agencies authority only over certain “navigable waters,” see, 5 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 16 e.g., id. § 1362(12), defining such waters as “waters of the United States, including the territorial seas,” id. § 1362(7). The definition of “waters of the United States” determines the scope of numerous provisions in the CWA, including obligations imposed upon the States. Subject to certain exclusions, any person who causes pollutant discharges into “waters of the United States” must obtain a permit under the section 402 National Pollutant Discharge Elimination System (“NPDES”) program, id. § 1342, or under section 404 of the CWA for the discharge of dredged or fill material, id. § 1344. Forty-six States have assumed NPDES permitting responsibilities within their borders under 33 U.S.C. § 1342(b), NPDES Program Authorizations, https://www.epa.gov/npdes/npdes-program-authorizations (last visited October 31, 2016); another two have assumed section 404 permitting under 33 U.S.C. § 1344(g), 40 C.F.R. § 233.70-.71. All States are responsible for developing water quality standards for those “waters of the [United] State[s]” that lie within their borders. 33 U.S.C. § 1313. They must report on the condition of those waters to EPA every two years, id. § 1315, and if waters are not achieving their designated standards, the States must develop detailed pollution diets for the underperforming waters and submit those plans to EPA for approval, id. § 1313(d). Finally, States must issue water quality certifications for every federal permit that is issued by EPA or the Corps within their borders. Id. § 1341. In short, the regulatory 6 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 17 obligations of the thirty-one State Petitioners under the CWA are inextricably entwined with the scope of federal jurisdiction established by the term “waters of the United States.” For waters that are not subject to section 402 or 404 permitting requirements, the States regulate the water quality and use of such waters under their independent sovereign authority. See, e.g., N.D. Cent. Code §§ 61-28-01 et seq.; Mont. Code Ann. §§ 75-5-101 et seq.; N.M. Stat. Ann. §§ 74-6-4 et seq.; Mo. Rev. Stat. §§ 644.006 et seq.; Ark. Code Ann. §§ 8-4-101 et seq.; Tex. Water Code §§ 26.001 et seq.; Ky. Rev. Stat. §§ 224.70-100 et seq. B. Supreme Court Precedent The Rule is not the first time the Agencies have attempted to expand their jurisdiction through unlawful interpretation of the statutory phrase “waters of the United States.” The Supreme Court has twice in the last fifteen years rejected the Agencies’ overbroad reading of that phrase. In SWANCC, the Court invalidated the Migratory Bird Rule, which asserted jurisdiction over waters “[w]hich are or would be used as habitat” by migratory birds. 531 U.S. at 164. The Corps exceeded its authority, the Court held, because it claimed authority over “nonnavigable, isolated, intrastate waters,” id. at 172, such as seasonal ponds, id. at 163. The Court supported its determination by finding that the Corps’ interpretation would “alter[] the federal-state framework by 7 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 18 permitting federal encroachment upon a traditional state power”—specifically, the States’ “traditional and primary power over land and water use.” Id. at 173-74. The Court held that Congress had not, in the CWA, “express[ed] a desire to readjust the federal-state balance in this manner” or to invoke the “outer limits” of its power. Id. at 172-74. In Rapanos, the Court rejected the Corps’ assertion of authority over intrastate wetlands that are not significantly connected to navigable-in-fact waters. 547 U.S. 715. The Court’s majority consisted of a four-Justice plurality opinion and Justice Kennedy’s concurrence in the judgment. The plurality concluded that the CWA “includes only those relatively permanent, standing or continuously flowing bodies of water ‘forming geographic features’ that are described in ordinary parlance as ‘streams[,] . . . oceans, rivers, [and] lakes,’” Rapanos, 547 U.S. at 739 (Scalia, J., plurality) (quoting Webster’s New International Dictionary 2882 (2d ed. 1954)), and “wetlands with a continuous surface connection to” those waters, id. at 742. The plurality said that “channels through which water flows intermittently or ephemerally, or channels that periodically provide drainage for rainfall” are outside CWA jurisdiction. Id. at 739. Justice Kennedy, in turn, explained that the Agencies only have authority over waters that are navigable-in-fact and waters with a “significant nexus” to such navigable waters. 547 U.S. at 779 (Kennedy, J., concurring in the judgment) 8 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 19 (citing United States v. Appalachian Power Co., 311 U.S. 377, 407-08 (1940)). A water has a “significant nexus” if it “significantly affect[s] the chemical, physical, and biological integrity of” a navigable water. Id. at 779-80. Under Justice Kennedy’s approach, the Agencies are not permitted to assert jurisdiction over all “wetlands (however remote)” or all “continuously flowing stream[s] (however small).” Id. at 776; see also id. at 769 (“merest trickle, [even] if continuous” is insufficient). Justice Kennedy also specifically rejected the Corps’ “theory of jurisdiction,” namely, any “adjacency to tributaries, however remote and insubstantial.” Id. at 780. C. The Proposed Rule On April 21, 2014, the Agencies published a proposed rule redefining “waters of the United States.” 79 Fed. Reg. 22,188 (Apr. 21, 2014) (“Proposed Rule”). The Agencies proposed to categorize primary waters as “all waters which are currently used, were used in the past, or may be susceptible to use in interstate or foreign commerce,” as well as “[a]ll interstate waters, including interstate wetlands” and “the territorial seas.” Id. at 22,262. The Proposed Rule then provided three additional categories of waters that would fall within the definition of “waters of the United States”: (1) all “tributaries” of primary waters would be per se jurisdictional; (2) all waters “adjacent” to primary waters would be per se jurisdictional, with “adjacency” defined as including all waters lying in a “riparian 9 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 20 area” or “flood plain”; and (3) additional waters, on a case-by-case basis, that “alone or in combination with other similarly situated waters, including wetlands, located in the same region, have a significant nexus to a” primary water, meaning they “significantly affect[] the chemical, physical, or biological integrity” of a primary water. Id. at 22,269. The Proposed Rule triggered more than one million comments, including comments from the States. A prevailing theme in many of the State comments was that the proposal reached too many local water and land features that are remote from navigable waters. See, e.g., Multi-State Comments 2, ID-7988 (JA__);1 WY DEQ Comments 3, ID-18020 (JA__); AK DEC Comments 27, ID-19465 (JA__); TX AG Comments 6, ID-5143 (JA__). The States also expressed concern that the Connectivity Study, used as the primary scientific support for the Proposed Rule, failed to address adequately the significance of the connection between waters. See, e.g., AK DEC Comments 11-12, ID-19465 (JA__); ND Comments 5-6, ID15365 (JA__). The States were also concerned that only a draft of the Connectivity Study was available during the comment period. Comments 11, ID-19465 (JA__). See AK DEC The Agencies failed to release a final and 1 Citations to record materials within this brief are as follows: short title, a pinpoint page reference if applicable, an abbreviated EPA docket number, and a reference to the joint appendix. 10 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 21 significantly revised version of that report until two months after the close of the comment period. See Connectivity Study, ID-20859 (JA__); 80 Fed. Reg. 2,100 (Jan. 15, 2015). Commenters also called for the Corps to comply with NEPA by preparing an Environmental Impact Statement (“EIS”) assessing the environmental and socioeconomic effects of the Proposed Rule, as compelled by 42 U.S.C. § 4332(2)(C). See AK DEC Comments 15-16, ID-19465 (JA__). The Corps ignored those comments and instead prepared a more streamlined Environmental Assessment (“EA”)2 and corresponding Finding of No Significant Impact (“FONSI”),3 determining that the Rule fell below the significance threshold triggering the need for full evaluation in an EIS. And it waited to release those reports until six months after the close of the public comment period, shielding the Agencies from public scrutiny. Compare 79 Fed. Reg. 61,590, 61,591 (Oct. 14, 2014) (comments on proposed rule due November 14, 2014), with Final EA, ID20867 (JA__) (released May 26, 2015). D. The Final Rule The Agencies published the Final Rule in the Federal Register on June 29, 2015. The Rule incorporates the proposal’s definition of primary waters and 2 3 Final EA, ID-20867 (JA__). FONSI, ID-20867 (JA__). 11 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 22 largely retains the proposal’s sweeping approach to “tributaries,” but then adopts a significantly different approach to “adjacent” waters and case-by-case waters. Importantly, several of the central components that guide the Rule’s approach for adjacent waters and case-by-case waters are not even discussed, let alone analyzed, in the administrative record. In general, the Rule includes three aspects that are relevant for the States’ challenge in the present case: Tributaries. The Rule claims per se jurisdiction over “[a]ll tributaries,” 33 C.F.R. § 328.3(a)(5),4 defined as any “water that contributes flow, either directly or through another water” to a primary water and that is “characterized by the presence of the physical indicators of a bed and bank and an ordinary high water mark,” id. § 328.3(c)(3). This includes even usually dry channels that provide “intermittent or ephemeral” flow through “any number” of links. 80 Fed. Reg. at 37,076. Adjacent Waters. The Rule asserts automatic jurisdiction over all waters “adjacent” to primary waters and their “tributaries.” 33 C.F.R. § 328.3(a)(6). The Rule defines “adjacent” as all waters “bordering, contiguous, or neighboring” 4 The Final Rule’s definition of “waters of the United States” is located in multiple parts of the Code of Federal Regulations. For ease of reference, this brief refers to the first location identified in the Rule, 33 C.F.R. Part 328. 12 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 23 primary waters, impoundments, or tributaries. Id. §328.3(c)(1). This includes “waters separated by constructed dikes or barriers, natural river berms, beach dunes, and the like.” Id. Departing significantly from the Proposed Rule, the Final Rule then defines “neighboring” to cover: (1) “all waters” any part of which are within 100 feet of the ordinary high water mark of a primary water or “tributary;” (2) “all waters” any part of which are within 1,500 feet of the ordinary high water mark of a primary water or “tributary” and within its 100-year floodplain; and (3) all waters any part of which are within 1,500 feet of the high tide line of a primary water. Id. §328.3(c)(2). The Final Rule also adds an exclusion from the adjacent waters categories— not even mentioned in the Proposed Rule—for “[adjacent w]aters being used for established normal farming, ranching, and silviculture activities.” Id. § 328.3(c)(1). The Agencies did not explain why the per se jurisdictional tributaries category contains no similar exclusion. Case-by-case Waters. The Final Rule allows the Agencies to exercise authority on a case-by-case basis over waters and land features in a way that differs significantly from the proposal. The Rule grants the Agencies authority, on a caseby-case basis, over those “waters [at least partially] located within the 100-year floodplain of a” primary water and “waters [at least partially] located within 4,000 feet of the high tide line or ordinary high water mark of a” primary water, 13 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 24 impoundment, or tributary so long as the Agencies find a significant nexus with a primary water. Id. § 328.3(a)(8). Under the Final Rule, a water will be deemed to have a “significant nexus” to a primary water if that water, “either alone or in combination with other similarly situated waters in the region, significantly affects the chemical, physical, or biological integrity of a [primary water]” based on “any single function or combination of functions performed by the water.” Id. § 328.3(c)(5) (emphasis added). For example, if bird species like ducks use hydrologically isolated wetlands for foraging and feeding, that use would extend federal jurisdiction to the isolated wetland. See 80 Fed. Reg. at 37,093. The same would be true if insects breed in an isolated wetland or marsh and then terminate their life cycle as food for fish or fowl in a non-navigable stream that crosses a state border. See id. And isolated wetlands or depressions could be deemed jurisdictional precisely because of their isolation—if the Agencies determine that such features store water, trap sediment, or cycle nutrients, they can be deemed jurisdictional individually or in conjunction with other similar waters. See id. E. This Litigation After the Rule was published in the Federal Register, thirty-one States filed petitions for review in courts of appeals. Pursuant to 28 U.S.C. § 2112, those petitions were consolidated in this Court. On October 9, 2015, this Court stayed 14 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 25 the Rule nationwide, finding that “it is far from clear that the new Rule’s distance limitations are harmonious” with Rapanos, and that “the rulemaking process by which the distance limitations were adopted is facially suspect.” In re EPA, 803 F.3d 804, 807 (6th Cir. 2015). After granting the stay, this Court held that it has jurisdiction under 33 U.S.C. § 1369(B)(1)(F). In re U.S. Dep’t of Defense and U.S. EPA Final Rule, 817 F.3d at 274; id. at 282-83 (Griffin, J., concurring in the judgment). SUMMARY OF ARGUMENT I. The Rule exceeds the Agencies’ authority under the CWA. Agencies can only exercise power that has been delegated to them by Congress. In just the last fifteen years, the Supreme Court has twice rebuked the Agencies for regulating beyond the boundaries set by Congress in the CWA, but the Agencies continue to defy those boundaries. In fact, the Rule regulates the very same waters the Court held fall outside the scope of the CWA in SWANCC and Rapanos. The Agencies claim to rely exclusively on Justice Kennedy’s Rapanos concurrence, but the Rule plainly violates this approach. For example, the Rule’s tributaries category sweeps in usually dry channels that at most occasionally carry the “[t]he merest trickle[s]” into navigable waters. Rapanos, 547 U.S. at 769 (Kennedy, J., concurring in the judgment). The adjacency category covers waters 15 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 26 simply because they are somewhat near a remote “tributary,” which are the very same waters that Justice Kennedy specifically explained fell outside of the CWA. See id. This category also asserts jurisdiction over land features that might link to navigable waters, if at all, only during once-in-a-century rainstorms, which exceeds any reasonable notion of a “significant nexus.” And the case-by-case waters category sweeps in—among many other features—the very same waters that the Supreme Court held were not jurisdictional in SWANCC, a decision that Justice Kennedy relied upon heavily. The Rule also fails the test set out in the Rapanos plurality opinion because it includes isolated tributaries, non-adjacent waters misleadingly termed “adjacent,” and waters on a case-by-case basis that also are without a surface connection to relatively permanent navigable waters. The Agencies do not even argue that the Rule satisfies this test, and any such argument would be impossible. Even if the Rule were not prohibited by the Supreme Court’s clear directives on the meaning of the phrase “waters if the United States,” the Rule’s assertion of broad authority at, and beyond, constitutional limits requires clear congressional authorization. The Supreme Court in SWANCC held that the assertion of federal authority in that case was unlawful, in part, to avoid serious constitutional concerns. These concerns apply with much greater urgency to the Rule, which covers not only the very same waters at issue in SWANCC, but innumerable other 16 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 27 local land and water features, the regulation of which is a core sovereign function of the States. II. The Agencies adopted the Rule in plain violation of the APA. The Agencies unlawfully built the Final Rule around five distance-based components and an unduly narrow exclusion that are not even arguably a “logical outgrowth” of the proposal. The Final Rule’s adjacency and case-by-case waters categories are oriented around several distance-based components that were nowhere mentioned in the Proposed Rule. The Agencies’ notice was so lacking as to these components that the Agencies have not been able to identify even a single comment, out of more than a million, that addresses any of the components. This sort of procedural failure would be unacceptable as to any agency rule, but it is particularly egregious given the context of this rulemaking, which defines how millions of acres of local land and water features will be regulated. The Agencies’ failure to comply with the APA’s notice-and-comment requirements contributed to another APA violation: the failure to offer record support for the Final Rule. The five distance-based components and the unduly narrow exclusion lack any record support, forcing the Agencies to rely upon vague assertions of “reasonable and practical” distinctions and unspecified “experience” to justify their inclusion. 80 Fed. Reg. at 37,085-91. These conclusory statements are insufficient to justify the Rule. 17 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 28 The Agencies’ “significant nexus” analysis in support of the Final Rule is similarly problematic. The Agencies rely heavily on the scientific analysis in their Connectivity Study to support their expansive new assertion of jurisdiction. But the science simply supports the unremarkable conclusion that upstream waters are connected to downstream waters. The science does not establish the significance of that connection, as the law requires. III. The Rule violates the Constitution in three principal ways. First, it intrudes upon the States’ sovereign interests in regulating their land and water resources in violation of the Tenth Amendment, contrary to the core federalism principles also reflected in the CWA. See 33 U.S.C. § 1251(b). The Rule asserts jurisdiction over local land and water features that have only a remote connection, if any, to navigable-in-fact waters, turning the Agencies into a “de facto” federal “zoning board.” Rapanos, 547 U.S. at 738 (Scalia, J., plurality). This imposes significant burdens on the States, and deprives the States of their sovereign land-use authority. Second, the Rule exceeds Congress’s constitutional authority under the Commerce Clause because it assigns the federal government jurisdiction over isolated, intrastate waters with no meaningful impact on or connection to interstate commerce. See SWANCC, 531 U.S. at 173. 18 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 29 Third, the Rule violates the Due Process Clause because it is unconstitutionally vague. The Rule defines jurisdictional tributaries based on the presence of ordinary high water marks and other difficult-to-identify features, which are “so vague that men of common intelligence must necessarily guess at [their] meaning and differ as to [their] application,” Ass’n of Cleveland Fire Fighters v. City of Cleveland, 502 F.3d 545, 551 (6th Cir. 2007). Similarly, the Rule allows the Agencies to assert jurisdiction over waters on a case-by-case basis without providing sufficient guidance for making such a determination, making it impossible for ordinary citizens to know when their lands will be swept within the CWA on an enforcement agent’s whim. IV. The Corps violated NEPA in at least three ways. First, the Corps violated NEPA by failing to prepare an EIS analyzing the environmental and socioeconomic effects of the Final Rule. As one of the most far-reaching regulations ever adopted in the environmental arena, the Rule easily triggered NEPA’s EIS requirement. Second, the Corps relied on a wholly inadequate EA to determine that the Final Rule will not have significant effects on the human environment. The EA was devoid of analysis of key factors that, if considered, would have prompted any reasonable agency to prepare an EIS. 19 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 30 Third, the Corps’ alternatives analysis was similarly defective. The Corps analyzed only two options: the Final Rule and the existing post-Rapanos regulatory regime. The Corps ignored reasonable and feasible alternatives, including several raised by the States during the public comment period on the Proposed Rule. By narrowing the range of alternatives considered, the Corps narrowed its scope of review, depriving the public and the States of meaningful participation. ARGUMENT I. THE RULE VIOLATES THE CLEAN WATER ACT. The Rule’s interpretation of the statutory term “waters of the United States” in the CWA cannot be squared with the Act or the Supreme Court’s understanding of that term. As the CWA makes clear, “waters of the United States” is synonymous with “navigable waters.” 33 U.S.C. §§ 1362(7), 1362(12). This means that any reasonable interpretation of “waters of the United States” must apply to navigable-in-fact waters and, at the very most, additional waters that directly impact the water quality of navigable-in-fact waters. The plain terms of the CWA do not permit the Agencies to sweep in local, isolated waters and land features, which have only a tangential relationship to navigable-in-fact waters. In fact, it is a “central requirement” of the Act that “the word ‘navigable’ in ‘navigable waters’ be given some importance.” Id. at 778 (Kennedy, J., concurring in the judgment). 20 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 31 In two opinions, a majority of the Supreme Court in Rapanos rejected a previous attempt by the Corps to define the phrase “waters of the United States” in a manner that swept in waters remote from navigable-in-fact waters. A four justice plurality concluded that the phrase applies only to “relatively permanent, standing or continuously flowing bodies of water ‘forming geographic features’ that are described in ordinary parlance as ‘streams[,] . . . oceans, rivers, [and] lakes.’” Rapanos, 547 U.S. at 739 (Scalia, J., plurality). Justice Kennedy concurred in the judgment, explaining instead that “waters of the United States” includes waters “navigable in fact or that could reasonably be so made” and waters with a “significant nexus” to a navigable-in-fact water. See id. at 759, 779 (Kennedy, J., concurring in the judgment). Under Marks v. United States, 430 U.S. 188 (1977), “[w]hen a fragmented Court decides a case[,] . . . the holding of the Court may be viewed as that position taken by those Members who concurred in the judgments on the narrowest grounds.” Id. at 193 (citation omitted). This Court has not yet decided which opinion controls under Marks, see United States v. Cundiff, 555 F.3d 200, 208-09 (6th Cir. 2009), and it need not do so here. Given that the Agencies justified the Rule based solely on Justice Kennedy’s test, the Rule must be held unlawful if it fails that test. See SEC v. Chenery Corp., 318 U.S. 80, 95 (1943). Even if the Agencies are not bound by their reliance on Justice Kennedy’s test, the Rule also 21 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 32 fails the plurality’s test. And, at the very minimum, if any doubt remains as to the Rule’s legality under either test, that doubt is settled under avoidance principles— as invoked by the Supreme Court in SWANCC—because the Rule goes to (and beyond) the limits of Congress’s constitutional authority and settles questions of deep political significance. A. The Rule Fails Justice Kennedy’s Significant Nexus Test. In Rapanos, Justice Kennedy concluded that the CWA covers only “waters that are or were navigable in fact or that could reasonably be so made” and secondary waters with a “significant nexus” to a navigable-in-fact water. 547 U.S. at 759 (Kennedy, J., concurring in the judgment). A significant nexus exists where the water “either alone or in combination with similarly situated lands in the region, significantly affect[s] the chemical, physical, and biological integrity of” a navigable-in-fact water. Id. at 780. This means that the CWA does not include waters with a “speculative or insubstantial” nexus to navigable waters. Id. at 780. Thus, Justice Kennedy explained that the CWA does not extend to all “wetlands (however remote),” all “continuously flowing stream[s] (however small),” id. at 776, and all waters containing “[t]he merest trickle, [even] if continuous,” id. at 769. Justice Kennedy specifically rejected the Corps’ approach of sweeping in all wetlands actually adjacent to tributaries of navigable waters, “however remote and insubstantial,” id. at 778-79, explaining that the standard’s breadth “preclude[d] its 22 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 33 adoption,” id. at 781. The Rule violates Justice Kennedy’s approach in multiple respects. 1. Per Se Coverage Of “Tributaries.” The Rule’s provision that all “tributaries” of primary waters are per se “waters of the United States” cannot be squared with Justice Kennedy’s approach. Under the Rule, a tributary is any land feature with “a bed and banks and an ordinary high water mark” and that “contributes flow”—no matter how ephemeral—“either directly or through another water” to a primary water. 33 C.F.R. § 328.3(c)(3). This covers land features with “one or more constructed breaks (such as bridges, culverts, pipes, or dams), or one or more natural breaks (such as wetlands along the run of a stream, debris piles, boulder fields, or a stream that flows underground).” Id. If there is such a break, the feature is still a tributary if it has “a bed and banks and an ordinary high water mark [that] can be identified upstream of the break.” Id. A feature also qualifies as a tributary if it contributes flow (even through a chain of “any number” of other waters) to a primary water. Id.; 80 Fed. Reg. at 37,076. As a result, tributaries under the Rule include typically dry land features that indirectly and only occasionally contribute even a mere trickle into a navigable water. See 80 Fed. Reg. at 37,076. This wide-reaching definition fails Justice Kennedy’s test because it provides no “assurance” that jurisdictional waters have a significant nexus to a 23 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 34 navigable water. See Rapanos, 547 U.S. at 781 (Kennedy, J., concurring in the judgment). First, the Rule sweeps in features based upon the fact that they “contribute[] flow,” 33 C.F.R. § 328.3(c)(3), even if the flow is “intermittent” or “ephemeral” and “only in response to precipitation events,” 80 Fed. Reg. at 37,076-77; see also id. (adding that the presence of such “tributaries” may be “infer[red]” through “desktop tools” where not apparent through “direct field observation”). This disregards Justice Kennedy’s concern that the “volume and regularity” of flow are relevant to decide whether a feature plays a sufficient role in “the integrity of an aquatic system” to establish a significant nexus to a navigable-in-fact water, Rapanos, 547 U.S. at 781 (Kennedy, J., concurring in the judgment). Justice Kennedy expressly rejected jurisdiction over features with “[t]he merest trickle [even] if continuous.” Id. at 769. Second, the Rule’s ordinary high water mark (“OHWM”) criterion does not sufficiently identify “flow” to satisfy Justice Kennedy’s test. The Rule defines an OHWM as “that line on the shore established by the fluctuations of water and indicated by physical characteristics such as a clear, natural line impressed on the bank, shelving, changes in the character of soil, destruction of terrestrial vegetation, the presence of litter and debris, or other appropriate means that consider the characteristics of the surrounding areas.” 33 C.F.R. § 328.3(c)(6). In 24 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 35 Rapanos, Justice Kennedy rejected reliance on the OHWM as a “determinative measure” for establishing a significant nexus. 547 U.S. at 761, 781 (Kennedy, J., concurring in the judgment) (citing 33 C.F.R. § 328.3(e) (2005)). Justice Kennedy concluded that the use of an OHWM as a standard could “provide[] a rough measure of the volume and regularity of flow” if it were consistently applied. Id. at 781. “Yet the breadth of this standard . . . seems to leave wide room for regulation of drains, ditches, and streams remote from any navigable-in-fact water and carrying only minor water volumes toward it.” Id. Such a standard would sweep in waters “little more related to navigable-in-fact waters than were the isolated ponds held to fall beyond the Act’s scope in SWANCC.” Id. at 781-82. In fact, the Agencies’ own studies demonstrate that the presence of an OHWM has no connection to water flow and fails to provide assurance of a significant nexus to navigable waters. For example, a 2006 Corps study found “no direct correlation between the location of OHWM indicators and the inundation areas” in the arid southwest.5 Rather, the indicators are “frequently the result of moderate to extreme flood events,” and “are not associated with any return interval 5 Robert W. Lichvar et al., U.S. Army Corps of Eng’rs, Distribution of Ordinary High Water Mark (OHWM) Indicators and Their Reliability in Identifying the Limits of “Waters of the United States” in Arid Southwestern Channels 14 (2006), http://acwc.sdp.sirsi.net/client/search/asset/1001678; see also AMA Comments 1011, ID-13951 (JA__). 25 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 36 event or with physical channel features found in the field.” Id. Similarly, a 2013 Corps study concluded that “OHWM indicators are distributed randomly throughout the [arid west] landscape and are not related to specific channel characteristics.”6 The Rawhide Wash in Scottsdale, Arizona provides a compelling example of why these studies are accurate. The Wash only conveyed flow 12 times over a 15-year period, for a total of 18 hours during that time. City of Scottsdale Comments 3, ID-18024 (JA__). Like most washes in the city, the flow is highly episodic and infiltrates the permeable soils long before it reaches a navigable-in-fact water. Id. But that does not matter under the Rule, as this and similar dry washes in Arizona and throughout the arid southwest would be subject to automatic federal jurisdiction under the new tributary definition. In short, the presence of OHWM provides no indication of the regularity of flow and no indication of other channel characteristics that could justify a significant nexus. Third, the “bed and banks” requirement is an even less reliable measure of water flow than the OHWM rejected by Justice Kennedy. For example, “erosional channels or cuts often will appear to have a distinguishable bed and banks . . . , but [those] are not evidence that the channels actually contribute flow to [navigable 6 Lindsey Lefebvre, et al., U.S. Army Corps of Eng’rs, Survey of OHWM Indicator Distribution Patterns across Arid West Landscapes 17 (2013), http://acwc.sdp.sirsi.net/client/en_US/search/asset/1017540; see also AMA Comments 11, ID-13951 (JA__). 26 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 37 waters].” AMA Comments 9, ID-13951 (JA__); see also WAC Comments 34, ID14568 (JA__) (“Bed, banks, and OHWM can be seen even in features without ordinary flow.”). Particularly in the arid west, channels with a bed and banks do not necessarily convey even a minimal amount of water. See Freeport Comments 2, ID-14135 (JA__); City of Scottsdale Comments 3-5, ID-18024 (JA__). The bed and banks requirement thus provides no assurance that a water “significantly affect[s] the chemical, physical, and biological integrity of” a navigable water, Rapanos, 547 U.S. at 780 (Kennedy, J., concurring in the judgment). Fourth, any doubt about the propriety of the Rule’s tributaries category is dispelled by its inclusion of the remote “drains, ditches and streams” that Justice Kennedy explained fall outside the CWA. Id. at 781. The Rule covers “[d]itches with perennial flow, . . . [d]itches with intermittent flow that are a relocated tributary, or are excavated in a tributary, or drain wetlands, . . . [and] [d]itches, regardless of flow, that are excavated in or relocate a tributary.” 80 Fed. Reg. at 37,078 (emphasis added). These are the “drains, ditches and streams” carrying only minor water volumes that Justice Kennedy references. Rapanos, 547 U.S. at 781 (Kennedy, J., concurring in the judgment). The Agencies’ explanation that they will identify some ditches based not on current conditions but on the “historical presence of tributaries,” 80 Fed. Reg. at 37,078-79, simply confirms their failure to comply with the limits of Justice Kennedy’s analysis. 27 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 38 2. Per Se Coverage Of All “Adjacent” Waters. The Rule’s per se coverage of all “adjacent” waters is also irreconcilable with Justice Kennedy’s approach. The Rule defines adjacent waters as, inter alia, (1) “all waters [at least partially] located within 100 feet of the ordinary high water mark of a” primary water, impoundment, or tributary; (2) all “waters located within the 100-year floodplain of a” primary water, impoundment, or tributary “and not more than 1,500 feet from the ordinary high water mark of such water;” and (3) “all waters [at least partially] located within 1,500 feet of the high tide line of a” primary water. 33 C.F.R. § 328.3(c)(2). As a threshold matter, because the Rule’s per se coverage of “tributaries” is unlawful, any assertion of jurisdiction over “adjacent waters” is illegal to the extent it relies on a connection with a “tributary.” As explained above, the Rule’s coverage of tributaries violates Justice Kennedy’s test by sweeping in waters regardless of frequency, duration, or volume of flow or proximity to navigable waters. It follows that “adjacent waters” included solely on account of their connection to a tributary necessarily lack a “significant nexus” to interstate, navigable waters. Indeed, this aspect of the Rule flagrantly violates Justice Kennedy’s explicit holding in Rapanos. Justice Kennedy rejected the Corps’ prior approach of asserting jurisdiction over all wetlands actually adjacent to tributaries of navigable-in-fact waters. Rapanos, 547 U.S. at 778-83 (Kennedy, J., concurring 28 Case: 15-3822 in the judgment). Document: 130 Filed: 11/01/2016 Page: 39 In the Rule, the Agencies double down on this unlawful assertion of authority by defining adjacency itself far more broadly than the adjacency notion that Justice Kennedy found insufficiently robust when dealing with tributaries of navigable-in-fact waters. The adjacency definition itself fails to satisfy Justice Kennedy’s test, even when not dealing with tributaries. Most obviously, the first part of the Rule’s adjacency definition—per se coverage of all waters within the 100-year floodplain and within 1,500 feet of a primary water or a “tributary,” 33 C.F.R. § 328.3(c)(2)(ii)—extends to small ponds, drainages, and wetlands simply because they might have a relationship with such water during a once-in-a-century storm. That plainly violates Justice Kennedy’s approach in Rapanos, which requires “assurance” that a water “significantly affect[s]” the “chemical, physical, and biological integrity” of a “navigable waters in the traditional sense,” 547 U.S. at 779-81 (Kennedy, J., concurring in the judgment). As Justice Kennedy explained, “[a] mere hydrologic connection should not suffice in all cases,” because it “may be too insubstantial for the hydrologic linkage to establish the required nexus with navigable waters as traditionally understood.” Id. at 784-85. A once-in-a-hundred-years hydrologic connection is surely too insubstantial given its infrequency. 29 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 40 Thus, the Rule’s categorical claim of federal jurisdiction over all “adjacent” waters as far as 1,500 feet from a “tributary” is far more expansive than the Corps’ jurisdictional theory Justice Kennedy rejected in Rapanos as “precluded” by the CWA. See id. at 781; see also id. at 778-79 (Corps cannot regulate simply “whenever wetlands lie alongside a ditch or drain, however remote and insubstantial, that eventually may flow into traditional navigable waters.”). And the Rule’s labeling these waters as “adjacent” also fails under SWANCC, upon which Justice Kennedy relied in Rapanos. After noting that United States v. Riverside Bayview Homes, Inc., 474 U.S. 121 (1985), had upheld federal jurisdiction “over wetlands that actually abutted on a navigable waterway,” the Court in SWANCC rejected jurisdiction over “ponds that are not adjacent to open water.” 531 U.S. at 167-68; see also Sackett v. EPA, 132 S. Ct. 1367, 1370 (2012) (contrasting abutting waters in Riverside with non-adjacent waters in SWANCC and Rapanos); Summit Petroleum Corp. v. U.S. EPA, 690 F.3d 733, 744 (6th Cir. 2012) (using the Rapanos understanding that “adjacent” does not mean “merely ‘nearby’” in a Clean Air Act case). The Rule’s other two distance-based adjacency categories—“all waters [at least partially] located within 100 feet of the ordinary high water mark of a” primary water, impoundment, or tributary, and “all waters [at least partially] located within 1,500 feet of the high tide line of a” primary water—are similarly 30 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 41 unlawful. 33 C.F.R. § 328.3(c)(2). EPA’s Science Advisory Board noted that “‘the available science supports defining adjacency or determination of adjacency on the basis of functional relationships,’ rather than ‘solely on the basis of geographical proximity of distance to jurisdictional waters.’” 80 Fed. Reg. at 37,064 (citation omitted) (emphasis added). Yet, the Agencies based definitions of adjacent waters “solely” on “geographical proximity.” These definitions do not provide the necessary assurance that the covered land features “play an important role in the integrity of . . . navigable waters,” Rapanos, 547 U.S. at 781-82 (Kennedy, J., concurring in the judgment). 3. Case-By-Case Waters. The Rule’s approach to case-by-case jurisdictional waters is also inconsistent with Justice Kennedy’s test. Under the Rule, the Agencies can assert jurisdiction over all waters determined to have a “significant nexus to a” primary water, provided that the waters are: (1) “located within the 100-year floodplain of a” primary water; or (2) “located within 4,000 feet of the high tide line or ordinary high water mark of a” primary water, impoundment or tributary. 33 C.F.R. § 328.3(a)(8). Based on the “functions performed by the water,” a “significant nexus” exists if the water “either alone or in combination with other similarly situated waters in the region, significantly affects the chemical, physical, or biological integrity of a [primary water].” 33 C.F.R. § 328.3(c)(5) (emphasis added). The functions include, among others, “[c]ontribution of flow,” 31 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 42 “[e]xport of organic matter,” “[e]xport of food resources,” and “[p]rovision of life cycle dependent aquatic habitat” for “species located in” primary waters. Id. By EPA’s own admission, the definition covers “the vast majority of the nation’s water features.” Economic Analysis 11, ID-20866 (JA__). The Rule’s definition of “significant nexus” covers far more waters than permitted under Justice Kennedy’s approach. The Rule permits jurisdiction if a water affects just one aspect of a primary water, not just a navigable water: the “chemical, physical, or biological integrity” of that water. Thus, it expressly permits the Agencies to find a “significant nexus” based solely on a single function, such as “contribution of flow” or “provision of life cycle dependent aquatic habitat” for “species located in” primary waters. 33 C.F.R. § 328.3(c)(5). This means, for example, that the Rule allows for jurisdiction simply if a water affects “dispersal,” 80 Fed. Reg. at 37,063, 37,072, 37,094, which is when “[p]lants and invertebrates” “‘hitchhik[e]’” on waterfowl. Connectivity Study 5-5, ID-20859 (JA__). In contrast, Justice Kennedy would permit regulation of an intrastate water only where it “significantly affects” the “chemical, physical, and biological integrity” of a navigable water in the traditional sense. Rapanos, 547 U.S. at 780 (Kennedy, J., concurring in the judgment) (emphasis added). The difference is illustrated by the Supreme Court’s decision in SWANCC, on which Justice 32 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 43 Kennedy relied in developing his test. In SWANCC, the Supreme Court rejected the Corps’ argument that it had jurisdiction over isolated sand and gravel pits based merely on the presence of “approximately 121 bird species” that “depend upon aquatic environments for a significant portion of their life requirements.” 531 U.S. at 164. As Justice Kennedy explained in Rapanos, the Corps’ argument in SWANCC did not establish a sufficient “connection” between the isolated pits and navigable waters. 547 U.S. at 779 (Kennedy, J., concurring in the judgment). But under the Rule’s permissive approach to case-by-case waters, the asserted basis for jurisdiction in SWANCC would be sufficient. Several of the bases for jurisdiction discussed above—e.g., provision of “life cycle dependent aquatic habitat[s]” and impact on “dispersal”—are in practical effect no different from the Corps’ reliance in SWANCC on the mere presence of migratory birds (since, for example, such birds necessarily engage in “dispersal” as they fly from navigable-in-fact to remote waters). 4. Interstate, Non-Navigable Waters. The Rule also violates Justice Kennedy’s test because its definition of primary waters—from which the Rule’s definitions of tributaries, adjacency, and case-by-case waters then operate— includes a category of waters that are not “navigable in fact,” Rapanos, 547 U.S. at 778 (Kennedy, J., concurring in the judgment), and “could [not] reasonably be so made,” id. at 759. Specifically, the Rule’s primary waters definition covers 33 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 44 “interstate waters, including interstate wetlands,” 33 C.F.R. § 328.3(a)(2), even where such waters are not “navigable in fact” and “could [not] reasonably be so made,” Rapanos, 547 U.S. at 759, 778 (Kennedy, J., concurring in the judgment). Under Justice Kennedy’s test, the CWA protects waters that are navigable and those additional waters that have a significant nexus to such navigable waters. Both Justice Kennedy and the statutory text make clear that non-navigable waters—whether they are interstate or not—are not the focus of the CWA. Accordingly, the Rule should not premise jurisdiction over non-navigable waters on a purported significant nexus to non-navigable interstate waters. To the extent that any category of such interstate waters is covered by the CWA, they could only be included under Justice Kennedy’s approach after a showing that they have a significant nexus to navigable-in-fact waters. B. The Rule Fails The Rapanos Plurality’s Test. Although the Agencies are precluded from arguing that the Rapanos plurality opinion justifies the Final Rule, see Chenery, 318 U.S. at 95, such an argument would fail in any event. The Rapanos plurality concluded that the CWA “includes only those relatively permanent, standing or continuously flowing bodies of water ‘forming geographic features’ that are described in ordinary parlance as ‘streams[,] . . . oceans, rivers, [and] lakes,’” Rapanos, 547 U.S. at 739 (Scalia, J., plurality) (quoting Webster’s New International Dictionary 2882 (2d ed. 1954)), 34 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 45 and “those wetlands with a continuous surface connection to” those waters, id. at 742. It does not include “channels through which water flows intermittently or ephemerally, or channels that periodically provide drainage for rainfall.” Id. at 739. The Rule violates these principles for at least four reasons. First, the Rule’s tributary definition includes features with intermittent or ephemeral flow in excess of the Rapanos plurality’s reading of the CWA. The Agencies admit that the Rule covers “perennial, intermittent, [and] ephemeral” streams with “flowing water only in response to precipitation events in a typical year.” 80 Fed. Reg. at 37,076. But the plurality specifically found it unreasonable to read “waters of the United States” to include “channels containing merely intermittent or ephemeral flow.” Rapanos, 547 U.S. at 733 (Scalia, J., plurality). Second, the Rule’s per se coverage of adjacent waters fails the plurality’s test because it does not require any continuous surface connection to relatively permanent bodies of water. The Rule includes all waters within the 100-year floodplain and within 1,500 feet of the OHWM of a primary water regardless of actual connectivity or the significance of that connectivity. § 328.3(c)(2)(ii). 33 C.F.R. Many waters in these areas are on average connected to a primary water only once every one-hundred years, which falls far short of a “continuous surface connection” with a relatively permanent water. In addition, the Rule includes waters based solely on a connection to a “tributary,” which as 35 Case: 15-3822 Document: 130 Filed: 11/01/2016 explained earlier can be usually dry channels. Page: 46 Although there may be a connection, that connection is not to a “relatively permanent, standing or flowing bod[y] of water.” See Rapanos, 547 U.S. at 732. And because the Rule includes waters based solely on certain distances, including from any “tributary” in a long chain, see 33 C.F.R. § 328.3(c)(2), it sweeps in waters with no surface connection to any body of water, let alone a continuous surface connection to a primary water. Third, the Rule’s assertion of case-by-case jurisdiction also covers waters with no continuous surface connection to a relatively permanent body of water, in violation of the Rapanos plurality. The Rule’s definition of “significant nexus” can be satisfied based on any one of a number of functions, which can be present even if a continuous surface connection is absent. For example, a usually dry channel could meet the requirement for “[c]ontribution of flow,” 33 C.F.R. § 328.3(c)(5), during a rare heavy rainstorm and yet lack “a continuous surface connection” with the water. Similarly, an isolated body of water that is used by some wildlife might affect the “[p]rovision of life cycle dependent aquatic habitat . . . for species located in a [primary] water,” 33 C.F.R. § 328.3(c)(5), and yet lack a “continuous surface connection” with the primary water. Fourth, the Rule’s inclusion of non-navigable interstate waters as a primary water, 33 C.F.R. § 328.3(a), also violates the plurality’s approach. The plurality held that the CWA is concerned with protecting “a relatively permanent body of 36 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 47 water connected to traditional interstate navigable waters.” Rapanos, 547 U.S. at 742 (Scalia, J., plurality). Clearly, non-navigable interstate waters fall outside of that understanding. C. The Rule Is Not Clearly Authorized By The CWA. Even if the Rule were not plainly foreclosed by the CWA, the Rule would still exceed the Agencies’ statutory authority because its transformational exercise of authority is not clearly authorized by Congress. It is well-established that “‘Congress legislates against the backdrop’ of certain unexpressed presumptions,” Bond v. United States, 134 S. Ct. 2077, 2088 (2014) (citing EEOC v. Arabian Am. Oil Co., 499 U.S. 244, 248 (1991)), two of which apply here. The first is that Congress does not delegate to agencies authority at the outer reaches of Congress’s power except in clear terms. SWANCC, 531 U.S. at 172 (citing Edward J. DeBartolo Corp. v. Fla. Gulf Coast Bldg. & Constr. Trades Council, 485 U.S. 568, 575 (1988)). “This concern is heightened where the administrative interpretation alters the federal-state framework by permitting federal encroachment upon a traditional state power.” Id. The second is that Congress does not grant transformative authority to regulate matters of vast political and economic significance absent a clear statement. Util. Air Regulatory Grp. v. EPA, 134 S. Ct. 2427, 2444 (2014) (“UARG”). Both of these presumptions require a clear 37 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 48 statement from Congress to justify the Rule’s assertion of the broad authority that it claims. Such a statement is clearly missing here.7 First, clear congressional authorization is required for a rule that raises serious federalism concerns. It is a “well-established principle that it is incumbent upon the federal courts to be certain of Congress’ intent before finding that federal law overrides the usual constitutional balance of federal and state powers.” Bond, 134 S. Ct. at 2089 (internal quotation and citation omitted); see also Gregory v. Ashcroft, 501 U.S. 452, 461 (1991). Thus, if Congress intends to legislate “in traditionally sensitive areas, such as legislation affecting the federal balance,” it must make its intention plain. United States v. Bass, 404 U.S. 336, 349 (1971); see also BFP v. Resolution Trust Corp., 511 U.S. 531, 544 (1994) (“To displace traditional state regulation . . . the federal statutory purpose must be ‘clear and manifest.’”); Tennessee v. FCC, 832 F.3d 597, 610 (6th Cir. 2016) (finding that “[a]ny attempt by the federal government to interpose itself into [the] statesubdivision relationship therefore must come about by a clear directive from Congress”). 7 For these and other reasons, the Agencies are not entitled to any deference under Chevron, U.S.A., Inc. v. Natural Resources Defense Council, 467 U.S. 837 (1984). See Opening Br. for the Business & Municipal Pet’rs Part III.C. 38 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 49 The Supreme Court applied this clear statement rule in SWANCC to invalidate an assertion of CWA jurisdiction by the Corps far less capacious than what is at issue in the Rule. Finding “nothing approaching a clear statement from Congress that it intended [the CWA] to reach an abandoned sand and gravel pit,” the Court rejected the agency’s claimed jurisdiction because it “would result in a significant impingement of the States’ traditional and primary power over land and water use.” SWANCC, 531 U.S. at 174. The Court noted that “[r]ather than expressing a desire to readjust the federal-state balance in this manner, Congress chose to ‘recognize, preserve, and protect the primary responsibilities and rights of States . . . to plan the development and use . . . of land and water resources.’” Id. (quoting 33 U.S.C. §1251(b)). Similarly, the plurality in Rapanos applied the clear statement rule to bolster its rejection of the Corps’ attempt to extend CWA jurisdiction to “intermittent” and “ephemeral flows of water.” 547 U.S. at 737-38 (Scalia, J., plurality). The plurality found that any attempt to federally regulate such water would not only be “an unprecedented intrusion into traditional state authority,” but would also “stretch[] the outer limits of Congress’ commerce power and raise[] difficult questions about the ultimate scope of that power.” Id. at 738. That sort of authority requires a “clear and manifest statement from Congress,” and “the phrase ‘the waters of the United States’ hardly qualifies” as such a statement. Id.; see also 39 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 50 id. (“[W]e would expect a clearer statement from Congress to authorize an agency theory of jurisdiction that presses the envelope of constitutional validity.”). The Rule likewise reaches and even exceeds the outer bounds of Congress’s constitutional authority. The Rule’s expansion of federal authority over intrastate waters will “impinge[] o[n] the States’ traditional and primary power over land and water use,” and “readjust the federal-state balance.” SWANCC, 531 U.S. at 174. The Rule’s coverage of intermittent waters, ephemeral waters, and isolated sometimes-wet lands “presses the envelope of constitutional validity,” Rapanos, 547 U.S. at 738 (Scalia, J., plurality) (citation omitted), far more than the challenged agency actions in Rapanos and SWANCC. The Agencies cannot point to a clear statement from Congress authorizing the expansion of authority they assert. The CWA provides only that the Agencies may require permits for pollutant discharges to “navigable waters” defined as “waters of the United States.” This text does not support the Agencies’ expansive interpretation, and certainly does not do so clearly. See SWANCC, 531 U.S. at 174. To the contrary, Congress expressed an intent to “recognize, preserve, and protect the primary responsibilities and rights of States . . . to plan the development and use . . . of land and water resources,” 33 U.S.C. § 1251(b). Second, recent Supreme Court cases have made clear that agencies cannot exercise transformative power over matters of vast economic and political 40 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 51 significance without clear congressional authorization. In UARG, EPA attempted to expand two Clean Air Act programs to cover sources based only on their greenhouse gas emissions. The Supreme Court rejected that effort, explaining that when an agency seeks to “bring about an enormous and transformative expansion” in its authority to make “decisions of vast ‘economic and political significance,’” UARG, 134 S. Ct. at 2444, under a “long-extant statute,” it must point to a clear statement from Congress, id. (citing FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120, 160 (2000)). The Supreme Court affirmed this principle last year in King v. Burwell, 135 S. Ct. 2480 (2015), holding that courts are not to presume that Congress would implicitly delegate to agencies “question[s] of deep ‘economic and political significance’” because, if “Congress wished to assign [such] question[s] to an agency, it surely would have done so expressly.” Id. at 2489 (citation omitted). In the Final Rule, the Agencies assert transformative authority. The Rule seeks to change fundamentally the allocation of federal and state authority in land and water use. As the plurality noted in Rapanos, “extensive federal jurisdiction . . . would authorize the [Agencies] to function as [] de facto regulator[s] of immense stretches of intrastate land . . . with the scope of discretion that would befit a local zoning board.” 547 U.S. at 738 (Scalia, J. plurality). By the Agencies’ own estimate, the Rule will result in an increase in determinations of federal jurisdiction 41 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 52 by 2.84 to 4.65 percent. 80 Fed. Reg. at 37,101. Even accepting as true this underinclusive estimation of the Final Rule’s expansion, but see, infra, section IV.A., this seemingly small percentage translates to the assertion of authority over a vast amount of additional water and sometimes-wet land. Such an expansion of authority conflicts with the findings of Rapanos and SWANCC and allows the Agencies to function as a zoning board with the authority to effectively regulate road construction, building construction, farming, and numerous other activities almost anywhere in the nation. See, e.g., ND Comments 3-4, ID-15365 (JA__); Multi-State Comments 12, ID-7988 (JA__). The economic implications of the Rule for the landowners, businesses, and public agencies that will be subject to additional federal permitting requirements further demonstrate the Rule’s transformative expansion of federal authority. As the Supreme Court observed recently, “[t]he costs of obtaining . . . a permit [from the Corps] are significant,” U.S. Army Corps of Eng’rs v. Hawkes, Co., 136 S. Ct. 1807, 1812 (2016), and “the permitting process can be arduous, expensive, and long,” id. at 1815 (citing Rapanos, 547 U.S. at 721 (Scalia, J., plurality)). Indeed, “[o]ver $1.7 billion is spent each year by the private and public sectors obtaining wetland permits alone.” Rapanos, 547 U.S. at 721 (Scalia, J., plurality) (quotation and citation omitted). And those are just the costs associated with permitting. Among other economic implications, the Rule’s expansion of the Agencies’ 42 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 53 authority will result in lost opportunities when permits improperly required under the expanded federal regime are delayed or are too costly to justify a project in the first place. See, e.g., AK DEC Comments 14, 16, ID-19465 (JA__, __); WAC Comments 78, ID-14568 (JA__). The Agencies cannot point to a clear statement from Congress authorizing such a transformative expansion of the Agencies’ authority over local land and water use. The phrase “waters of the United States” in the CWA cannot plausibly be construed to clearly authorize the wide reach of the Rule. II. THE RULE VIOLATES THE ADMINISTRATIVE PROCEDURE ACT. The APA includes two important safeguards relevant to this case. First, an agency must make its rules available for meaningful public comment. 5 U.S.C. § 553(b). Second, a reviewing “court shall . . . hold unlawful and set aside” any final rules that are “arbitrary [or] capricious.” Id. § 706(2)(A). There is a critical relationship between these two APA requirements, which this Rule starkly demonstrates. An agency’s failure to abide by the strictures of notice-and-comment rulemaking deprives the agency of meaningful comment, increases the likelihood of arbitrary decision-making, and frustrates the courts’ ability to conduct meaningful review. For example, when a party challenges a final rule in court, that party is generally “limited to the administrative record” in making its arguments. Latin Ams. for Soc. & Econ. Dev. v. Adm’r of the Fed. 43 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 54 Highway Admin., 756 F.3d 447, 464-65 (6th Cir. 2014). In turn, the record the party will need to rely upon will often consist of the “responsive data or argument” submitted during the notice-and-comment period. S. Rep. No. 752, 79th Cong., 1st Sess. 14 (1945). That is why one of the principal purposes of the notice-andcomment requirement is “to give affected parties an opportunity to develop evidence in the record to support their objections to the rule and thereby enhance the quality of judicial review.” See Int’l Union, UMWA v. MSHA, 407 F.3d 1250, 1259 (D.C. Cir. 2005); see also Ohio Dep’t of Human Servs. v. U.S. Dep’t of Health & Human Servs., 862 F.2d 1228, 1236 (6th Cir. 1988). Importantly, when an agency adopts a final rule that is not a “logical outgrowth” of the proposal, Long Island Care at Home, Ltd. v. Coke, 551 U.S. 158, 174 (2007), the result will often be the imposition of significant regulatory requirements on which the record is underdeveloped, or in an extreme example like this case, silent. The Final Rule here is a textbook example of such a breakdown in the APA’s processes. The Agencies constructed the Rule’s definition of “waters of the United States” around five central distance-based components and an unduly narrow exclusion that were not even arguably presaged in the proposal. This deprived parties of the opportunity to comment meaningfully on those components, thereby undermining informed agency decision-making and meaningful judicial review. These failures, in turn, contributed to the promulgation of a Rule that is 44 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 55 unsupported by any record evidence. These and other failures compel a finding that this rulemaking is arbitrary, capricious, and unlawful. A. The Agencies Built The Final Rule Around Distance-Based Components And An Unduly Narrow Exclusion That Were Never Submitted For Public Notice-And-Comment. The APA’s notice-and-comment mandate, 5 U.S.C. § 553(b), is “designed (1) to ensure that agency regulations are tested via exposure to diverse public comment, (2) to ensure fairness to affected parties, and (3) to give affected parties an opportunity to develop evidence in the record to support their objections to the rule and thereby enhance the quality of judicial review.” Int’l Union, 407 F.3d at 1259. These procedures “ensure that the broadest base of information would be provided to the agency by those most interested and perhaps best informed on the subject.” Phillips Petroleum Co. v. Johnson, 22 F.3d 616, 620 (5th Cir. 1994). To secure these critical objectives, the final rule must be a “logical outgrowth” of the proposal. Long Island, 551 U.S. at 174. A final rule satisfies that test if affected parties “should have anticipated that [the] requirement” embodied in the final rule might be adopted, including because the agency satisfied its duty of informing the public of “the range of alternatives being considered with reasonable specificity.” Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 549 (D.C. Cir. 1983). 45 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 56 The D.C. Circuit has explained that adopting a final rule that is not a logical outgrowth of the proposal “almost always requires vacatur.” Allina Health Servs. v. Sebelius, 746 F.3d 1102, 1110 (D.C. Cir. 2014). For example, in Small Refiner, EPA “gave general notice that it might make unspecified changes in the definition of small refinery.” 705 F.2d at 549. The D.C. Circuit held that the agency violated the APA in the final rule by adopting a date-of-ownership limitation on the definition of “small refinery.” Id. at 548-49. Similarly, in Shell Oil Co. v. EPA, 950 F.2d 741 (D.C. Cir. 1991), the court vacated a final rule where the listing of hazardous waste went from a “largely supplementary function” in the proposal to a “heavy emphasis” in the final rule. Id. at 751-52. And in CSX Transportation, Inc. v. Surface Transportation Board, 584 F.3d 1076 (D.C. Cir. 2009), the agency violated the APA by proposing to allow parties to recommend comparing data from the most recent year, but then adopting a rule that allowed data comparison over the past four years. Id. at 1082; accord Int’l Union, 407 F.3d at 1259-60; Envtl. Integrity Project v. EPA, 425 F.3d 992, 996 (D.C. Cir. 2005). Here, the Final Rule’s definition of “waters of the United States” includes five distance-based components and an unduly narrow exclusion that are not a logical outgrowth of the proposal. 1. The first three of these distance-based components involve the definition of per se “adjacent waters.” The Proposed Rule defined “adjacent waters” as all 46 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 57 waters within a so-called “riparian area” or “flood plain” of a primary water. 79 Fed. Reg. at 22,269. In the Final Rule, the Agencies adopted three entirely new distance-based components to define adjacency: (1) waters within 100 feet of a primary water, impoundment, or “tributary;” (2) waters within a 100-year floodplain and 1,500 feet of a primary water, impoundment, or “tributary;” and (3) waters within 1,500 feet of the high-tide line of a primary water. 33 C.F.R. § 328.3(c)(2). None of these three central “adjacency” distance-based components is a logical outgrowth of the proposal, because no interested party “should have anticipated” them, Small Refiner, 705 F.2d at 549. Had proper notice been given, parties from all sides would have submitted comments, data, and detailed maps, addressing the practical import and reasonableness of adopting these particular components. This did not occur because the public had no idea these components were being considered. Notably, the Agencies cannot identify a single public comment (out of over one million submitted) addressing these three distance-based components or the other new components discussed below. The best the Agencies can muster are comments discussing the merits and demerits of distance-based concepts in 47 Case: 15-3822 general. Document: 130 Filed: 11/01/2016 See, e.g., No. 15-3799, Dkt. 50-1, at 5.8 Page: 58 The one internal Corps memorandum, No. 15-3799, Dkt. 132-2, that this Court mandated be included in the administrative record confirms this point. Even the Corps was in the dark about these significant modifications to the proposed rule until months after the close of the public comment period. See Moyer Memorandum 1, ID-20882 (JA__). The Agencies’ approach thus resulted in a final rule that was never “tested via exposure to diverse public comment,” and was adopted in a manner manifestly “[un]fair[] to affected parties,” including because it gave “affected parties [no] opportunity to develop evidence in the record to support their objections to the rule.” Int’l Union, 407 F.3d at 1259. It also deprived the Agencies of information from those “most interested” and “best informed” regarding this subject matter: the regulated community and the state regulators who implement the CWA and related state programs at the field level. Phillips Petroleum, 22 F.3d at 620. The Agencies have argued that they did not violate the APA because in the Proposed Rule they sought comment on “‘establishing specific geographic limits’ 8 Even if the Agencies now manage to locate a comment or two guessing at one of the five standards or the unduly narrow exclusion, this would be of “little significance” because “the agency must itself provide notice of [its] proposal.” Ass’n of Private Sector Colls. & Univs. v. Duncan, 681 F.3d 427, 462 (D.C. Cir. 2012). Indeed, when comments are “sparse and ambiguous at best,” this supports the argument that the notice was not adequate. Shell Oil, 950 F.2d at 751. 48 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 59 for adjacency such as ‘distance limitations.’” Dkt. 47-1, at 5 (quoting 79 Fed. Reg. at 22,208-09). The Agencies’ position appears to be that because they asked about the merits of “geographical limitations” in general, they could then adopt, as a final rule, any distance-based definition of adjacency whatsoever, including both as to the reference point—e.g., “primary water, impoundment, or tributary;” “floodplain;” “high tide line;” or any other feature—and to the distance from that reference point—“100 feet,” “1,500 feet,” or any other distance—without seeking public input. This approach could be used to justify virtually “any final [adjacency] rule” and must be rejected. Envtl. Integrity, 425 F.3d at 998. While the Agencies’ approach would be unlawful regardless of the context, it is particularly unacceptable given the scope of this rulemaking. The decision as to what qualifies as a “water of the United States” affects how millions of acres of local land and water features are regulated for purposes of the entire CWA. If the Agencies wanted to build the definition of adjacency around distances from certain reference points, they were duty-bound to inform the public of “the range of alternatives being considered with reasonable specificity,” Small Refiner, 705 F.2d at 549, as to both the particular reference points themselves and the particular distances. The Agencies’ failure on this score led to an APA failure orders of magnitude more significant than the comparatively banal notice failures involving the definition of “small refinery,” Small Refiner, 705 F.2d at 549, whether the 49 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 60 listing of wastes would play a “supplementary” or “heavy” role, Shell Oil, 950 F.2d at 751-52, or whether data from one or four years could be considered, CSX, 584 F.3d at 1078. 2. The next two distance-based components that the Agencies unexpectedly adopted in the Final Rule relate to case-by-case waters. The proposal included a limitless, unlawful approach to these waters, providing that the CWA applied to any water that, in the Agencies’ judgment, had a “significant nexus” to a primary water. 79 Fed. Reg. at 22,269. In the Final Rule, the Agencies sought to address the illegality of their proposed approach, but did so in a manner that violated the notice-and-comment requirement (among other defects). Specifically, the Agencies provided that their case-by-case analysis would now relate to, as relevant here: (1) waters within the 100-year floodplain of a primary water; and (2) waters within 4,000 feet of a primary water, impoundment, or tributary. § 328.3(a)(8). 33 C.F.R. The Agencies’ decision to add these two distance-based components to the case-by-case waters inquiry violates the notice-and-comment requirement because no regulated parties “should have anticipated,” Small Refiner, 705 F.2d at 549, that the Agencies would adopt this approach. The Agencies’ defense of their actions with regard to adding these two components is no more credible than with regard to the three adjacency concepts discussed above. The most the Agencies have been able to muster is a citation to 50 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 61 the Proposed Rule’s observation that “‘distance of hydrologic connection’ is one of the factors that could be considered when evaluating a connection with a downstream water.” No. 15-3799, Dkt. 50-1, at 6 (quoting 79 Fed. Reg. at 22,214). But this opaque sentence appeared to be addressing factors that the Agencies would take into account in conducting their all-things-considered, caseby-case approach. It did not suggest that the Agencies were considering hard-andfast distance requirements for case-by-case waters, let alone inform the public of “the range of alternatives being considered with reasonable specificity,” Small Refiner, 705 F.2d at 549, as to either the particular reference points or the particular distances being considered. Notably, the subsections of the proposal that follow this single sentence consist of three-and-a-half pages discussing potential requirements for case-by-case waters, and none of the approaches contemplates adopting criteria based upon specific distances from specific reference points. See 79 Fed. Reg. at 22,214-17. 3. The sixth and final standard that the Agencies adopted in the Final Rule was that “waters being used for established normal farming, ranching, and silviculture activities” were excluded from per se jurisdiction under the Rule’s adjacency category, but not from the tributary category. 33 C.F.R. § 328.3(c)(1). The Agencies “nowhere even hinted,” CSX, 584 F.3d at 1082, that they were considering treating farmland differently as between the adjacency and “tributary” 51 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 62 categories. Had the Agencies informed the public that they were contemplating this exclusion, the States and farmers would have submitted comments explaining why farmland should be excluded from all per se categories. B. The Distance-Based Components And Unduly Narrow Exclusion Are Unsupported By The Record. The APA’s judicial review provision provides that a final rule must be “set aside” if that rule is “arbitrary [or] capricious.” 5 U.S.C. § 706(2)(A). While this inquiry is deferential, “[t]he arbitrary-and-capricious standard . . . does not require [courts] merely to rubber stamp the [agency’s] decision.” Kentucky Waterways Alliance v. Johnson, 540 F.3d 466, 474 (6th Cir. 2008) (citation omitted). A rule is arbitrary and capricious if it is unsupported by the record, Motor Vehicle Mfrs. Ass’n of United States, Inc. v. State Farm Mut. Ins. Co., 463 U.S. 29, 41-42 (1983), does not explain why alternatives were rejected, id., or fails to “treat similar cases in a similar manner unless it can provide a legitimate reason for failing to do so,” Indep. Petroleum Ass’n of Am. v. Babbitt, 92 F.3d 1248, 1258 (D.C. Cir. 1996). In addition, “conclusory statements will not do; an agency’s statement must be one of reasoning.” Amerijet Int’l, Inc. v. Pistole, 753 F.3d 1343, 1350 (D.C. Cir. 2014) (citation omitted). And judicial review becomes “meaningless where the administrative record is insufficient.” Nat’l Welfare Rights Org. v. Mathews, 533 F.2d 637, 648 (D.C. Cir. 1976). All five of the distance-based components and the 52 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 63 unduly narrow exclusion that the Agencies unexpectedly adopted in their Final Rule fail the APA’s “arbitrary [or] capricious” standard. 1. With regard to the three adjacency distance-based components, as well as the two case-by-case criteria, nothing in the record supports a per se jurisdictional finding for all waters and lands (1) within 100 feet of a primary water, impoundment, or tributary, (2) within a 100-year floodplain and 1,500 feet of a primary water, impoundment, or tributary, or (3) within 1,500 feet of the high tide line of a primary water. 33 C.F.R. § 328.3(c)(2). The same is true for case-bycase coverage focused upon (1) waters within the 100-year floodplain of a primary water, and (2) waters within 4,000 feet of a primary water, impoundment, or tributary. Id. § 328.3(a)(8). The Agencies argue that these distance-based components are “reasonable and practical,” consistent with unspecified “experience,” and supported by “the implementation value of drawing clear lines.” 80 Fed. Reg. at 37,085-91. Such “conclusory statements” are insufficient, Amerijet, 753 F.3d at 1350 (D.C. Cir. 2014), especially given the Agencies’ necessary concession that the Final Rule would be arbitrary and capricious if “the administrative record [failed to] support[] the bright-lines that the Agencies crafted,” No. 15-3799, Dkt. 50-1, at 8. And while some bright-line distance approaches could—perhaps—survive review given a proper administrative record, the record here is entirely 53 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 64 “insufficient.” See Nat’l Welfare, 533 F.2d at 648. To the extent the record says anything about this subject, the Agencies’ Science Advisory Board rejected any distance-based approach, arguing that “the available science supports defining adjacency or determination of adjacency on the basis of functional relationships, not on how close an adjacent water is to a navigable water.” SAB 2-3, ID-7531 (JA__). More generally, nothing in the record supports the Agencies’ decision to choose the specific distances—100 feet, 1,500 feet, 4,000 feet—over any alternative distances from any alternative reference points. Given that the Agencies adopted the distance-based components without record support and without explaining why alternative distances and reference points were rejected, State Farm, 463 U.S. at 41-42, and then justified these components by “conclusory” statements, Amerijet, 753 F.3d at 1350, the Rule is plainly unlawful. 2. The Rule’s exclusion of farmland from the per se adjacent waters category, but not the per se tributary category, is also arbitrary and capricious. The Agencies explained that this exclusion was justified in light of “the vital role of farmers in providing the nation with food, fiber, and fuel.” 80 Fed. Reg. at 37,080. While the States agree with this rationale, that justification applies just as strongly to excluding farmland from the per se tributary category. The Agencies’ failure to explain their decision to exclude farmland from one per se category, but not the 54 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 65 other, violates the mandate that an agency must “treat similar cases in a similar manner unless it can provide a legitimate reason,” Babbitt, 92 F.3d at 1258. C. The Rule’s Expansive Interpretation Of “Significant Nexus” Is Arbitrary And Capricious. The Agencies claim that their Rule is grounded in sound science—indeed, the term “science” is repeated ninety times in the preamble to the Rule, with an additional sixty-four references to the Agencies’ Connectivity Study. The Agencies also claim that “science,” as documented in the Connectivity Study, shows that Justice Kennedy’s significant nexus test is satisfied by the Rule’s expansive new definitions of “waters of the United States.” But the Connectivity Study only highlights a fundamental disconnect between the actual science and the Agencies’ claimed reliance on that science. According to the Agencies, the scientific basis for the Rule is that water flows downhill to create hydrological connections, see 80 Fed. Reg. at 37,063, and that the “protection of upstream waters is critical to maintaining the integrity of the downstream waters,” id. at 37,056. This is nothing but a truism, and implies a limitless expansion of federal power. Of course, upstream waters contribute to downstream waters, but that only establishes—at most—a “nexus” between the two. Whether any such nexus is “significant,” which is the key question in the Agencies’ conception of how to define “waters of the United States,” is a legal 55 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 66 question that, as the Agencies acknowledge, science does not answer. “While the agencies agree defining significant nexus by quantified metrics would improve clarity, for the reasons discussed in the Science Report . . . , such an approach is not supported by the science at this time.” RTC, Topic 9, 23, ID-20872 (JA__). At best, the science demonstrates that connectivity occurs along a continuum that “can be described in terms of frequency, duration, magnitude, timing, and rate of change.” Id. at 19. But the Agencies never explain anywhere in the record how or when these or other scientific factors demonstrate a significant nexus between downstream navigable waters that they have the unquestioned authority to protect, and the upstream waters that are within the States’ exclusive jurisdiction unless those waters have significant nexus to downstream navigable waters. Instead, the Agencies admit that while “[t]he science demonstrates that waters fall along a gradient of chemical, physical, and biological connection to traditional navigable waters, . . . it is the agencies’ task to determine where along that gradient to draw lines of jurisdiction under the CWA.” Id. at 21. And the Agencies made that determination based largely on (erroneous) legal and policy considerations, not science. Id. at 17 (“The rule reflects the judgment of the agencies when balancing the science, the statute, the Supreme Court opinions, the agencies’ expertise, and the regulatory goals of providing clarity to the public while protecting the environment and public health.”). 56 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 67 As explained above, those legal grounds are legally insufficient. The mere existence of a hydrological connection—even a continuous one—is insufficient under Justice Kennedy’s approach. Rapanos, 547 U.S. at 769. But that is all the Connectivity Study demonstrates; it can at most be used to establish a nexus, but not the significance of that nexus. The Agencies have therefore failed to “articulate a rational connection between the facts found” and the expansive definitions in the Final Rule, one of the hallmarks of arbitrary decision-making. See Bowman Transp., Inc. v. Arkansas-Best Freight Sys., Inc., 419 U.S. 281, 285 (1974). III. THE RULE VIOLATES THE CONSTITUTION. The Final Rule violates the U.S. Constitution in at least three ways. First, it intrudes upon the States’ sovereign interests in regulating their land and water resources in violation of the Tenth Amendment. Second, it exceeds Congress’s constitutional authority under the Commerce Clause because it provides for federal jurisdiction over isolated, intrastate waters with no meaningful impact on or connection to interstate commerce. And third, it violates the Due Process Clause because it is unconstitutionally vague. As a result, the Rule must be vacated. A. The Rule Violates The States’ Tenth Amendment Rights. Under the Tenth Amendment, “[t]he powers not delegated to the United States by the Constitution . . . are reserved to the States respectively, or to the 57 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 68 people.” U.S. Const., amend. X. Tenth Amendment concerns are implicated when a federal rule regulates the “states as states,” when it addresses matters that are indisputably attributes of state sovereignty, and when compliance with the rule would directly impair a State’s ability to structure integral operations in areas of traditional state functions. Hodel v. Va. Surface Mining & Reclamation Ass’n, Inc., 452 U.S. 264, 286-87 (1981). The federal system “protects the liberty of all persons within a State by ensuring that laws enacted in excess of delegated governmental power cannot direct or control their actions. . . . By denying any one government complete jurisdiction over all the concerns of public life, federalism protects the liberty of the individual from arbitrary power.” Bond v. United States, 564 U.S. 211, 222 (2011). State authority to regulate and manage local lands and waters is a core sovereign interest. Indeed, state authority in this realm “is perhaps the quintessential state activity.” FERC v. Mississippi, 456 U.S. 742, 768 n.30 (1982). That is why Congress so clearly recognized the States’ inherent powers over local lands and water resources in the CWA, see 33 U.S.C. § 1251(b), and purposefully integrated federalism principles throughout the Act. In SWANCC, the Supreme Court relied on this core “traditional state power” to explain its narrower interpretation of the CWA. 531 U.S. at 172-73. The provision of the rule at issue in SWANCC exceeded the Agencies’ authority, the Court held, because it covered 58 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 69 “nonnavigable, isolated, intrastate waters” such as seasonal ponds. Id. at 170-71. The Court supported its determination by finding that the Corps’ interpretation would “alter[] the federal-state framework by permitting federal encroachment upon a traditional state power”—specifically, the States’ “traditional and primary power over land and water use.” Id. at 173-74. The Rule’s overbroad assertion of authority over local land and water features that have only a remote connection to navigable-in-fact waters invades the States’ sovereign authority, in violation of their Tenth Amendment rights. As already discussed, the definitions in the Rule extend federal jurisdiction to remote, usually-dry, and entirely intrastate land and water features remote from any navigable waterway. Once the Agencies assert federal jurisdiction, they displace state and local land regulation, and act as a “de facto” federal “zoning board.” Rapanos, 547 U.S. at 738 (Scalia, J., plurality). The issue is not merely the breadth of jurisdiction asserted by the federal government, but also the scope of regulatory power that the federal government would exercise in those areas. See SWANCC, 531 U.S. at 173.9 Here, that regulatory power is the “[r]egulation of land use”—“a 9 Indeed, once federal jurisdiction is triggered, the potential scope of that power is exceedingly broad. See, e.g., 33 C.F.R. § 320.4(a) (identifying approximately 25 “public interest” factors the Corps considers when determining whether to issue a section 404 permit, including economic, aesthetics, land use, historic properties, safety, and food and fiber production). 59 Case: 15-3822 Document: 130 quintessential state and local power.” Filed: 11/01/2016 Page: 70 Rapanos, 547 U.S. at 738 (Scalia, J., plurality). The Rule’s expansion of federal jurisdiction over traditional state lands and water resources necessarily regulates “states as states,” Hodel, 452 U.S. at 286-87, because of the extensive cooperative federalism principles embodied in the CWA. For example, all States are required to develop water quality standards for federal jurisdictional waters within their borders. 33 U.S.C. § 1313. They must also review those standards at least every three years, id. § 1313(c), and report to EPA on the quality of all federal waters in the State every other year, id. § 1315(b). States must also develop complicated total maximum daily loads for any water not meeting established water quality standards. Id. § 1313(d). States are also required to issue water quality certifications for every permit the federal government issues within their borders, including section 404 permits issued by the Corps. See id. § 1341(a)(1). For the forty-six States with authority to implement the NPDES program under 33 U.S.C. § 1342, additional federal waters means additional permitting responsibilities. Michigan and New Jersey bear additional obligations, as the two States that have assumed authority to issue dredge and fill permits under 33 U.S.C. § 1344. Finally, expanded federal jurisdiction directly affects state highway, transmission line, and pipeline projects, triggering federal permitting requirements for potential impacts to newly-minted federal waters. See, 60 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 71 e.g., AK DEC Comments 14-15, ID-19465 (JA__); ADOT Comments 1, ID-15215 (JA__). The practical impact upon the States from the Rule’s expansion of federal authority is breathtaking. From prairie potholes in North Dakota, to arroyos in New Mexico, ephemeral drainages in Wyoming, and coastal prairie wetlands in Texas, the Final Rule extends jurisdiction to virtually every potentially wet area of the country. See 33 C.F.R. § 328.3(b). In fact, the Rule sweeps so broadly that the Agencies find it necessary explicitly to disclaim authority over “puddles” and swimming pools “created in dry land.” Id. § 328.3(b)(4). The Agencies acknowledge that “the vast majority of the nation’s water features are located within 4,000 feet of a covered tributary, traditional navigable water, interstate water, or territorial sea” and that the 100-year floodplain encompasses an even larger area. Economic Analysis 11, ID-20866 (JA__). These areas are swept within the jurisdictional reach of the Final Rule. Alaska presents a telling example. See AK DEC Comments 18-20, ID19465 (JA__). Forty-three percent of Alaska is wetlands, covering more than 174 million acres. Many of those wetlands are frozen much of the year, and are underlain with permafrost. During the warmer seasons, the surface soils become inundated when thawing conditions generate near-surface water that cannot penetrate the underlying permafrost, causing the soils to exhibit wetland-like 61 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 72 characteristics. These areas can extend for hundreds of miles inland from the main navigable-in-fact waterways, as much of northern Alaska is covered in “continuous permafrost.” Id. at 19, Att. 5 (JA__, __). Under the Rule, these lands are subject to federal jurisdiction by virtue of the straddling provision contained in the Rule’s definition of neighboring: “The entire water is neighboring if a portion is located within 1,500 feet of the ordinary high water mark and within the 100-year floodplain.” 33 C.F.R. § 328.3(c)(2)(ii) (emphasis added). As Alaska warned the Agencies, the Proposed Rule would “federalize land use decisions for State, local and private lands” in Alaska because “nearly all waters and wetlands in Alaska” would be subject “to regulation by the EPA and the Corps.” AK Gov. Comments 1, ID-19465 (JA__). This conclusion applies just as much to the Final Rule. The City of Scottsdale, Arizona provides another compelling example in a completely different ecological region. See City of Scottsdale Comments, ID18024 (JA__). The City is replete with ephemeral drainages that flow in response to “high intensity and short duration storms.” Id. at 3 (JA__). The flow is limited in duration, and typically infiltrates through the highly permeable soils long before it reaches a navigable-in-fact water, if at all. See, e.g., id. (describing Rawhide Wash as flowing 0.014% of the time over a 15-year period). And a single storm may produce flow in one wash, but others a mile away could be bone dry. See id. But all washes in the region are marked by a bed and banks and an OHWM, 62 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 73 sometimes created after a single rain event. See id. These dry washes will be per se jurisdictional under the Rule, despite historically being treated as nonjurisdictional under the Agencies’ post-Rapanos guidance. See id. at 4 (JA__). The Rule’s additional regulation will come at a steep financial cost to the States. For example, the Agencies have estimated that the Rule will impose additional obligations on the States of between $798,000 and $1.3 million per year under the section 401 water quality certification program. Economic Analysis 19, ID-20866 (JA__). The NPDES storm water permit program will add $360,000 each year to state budgets, id. at 25 (JA__), and another $270,000 to regulate confined animal feeding operations, id. at 27-28 (JA__). The States believe that these and other estimates in the Agencies’ Economic Analysis are grossly understated. See, e.g., AK DEC Comments 17, ID-19465 (JA__); KS Comments 6, ID-14794 (JA__); WY DEQ Comments 5, ID-18020 (JA__). Alaska, for example, paid approximately $8 million to offset wetland and other impacts associated with the development of public projects between 2009 and 2015. AK DEC Comments 16, ID-19465 (JA__). “The[se] costs will only multiply with the additional waters that would become jurisdictional.” Id. These costs and increased regulatory obligations impair the States’ ability “to structure integral operations in areas of traditional state functions.” Hodel, 452 U.S. at 287-88 (internal quotation and citations omitted). The same is true for local governments. In Scottsdale, 63 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 74 Arizona, for example, the City fears that the per se assertion of jurisdiction over the region’s many dry washes will have “detrimental impacts” on “proposed development projects” and on “City transportation, parks, and drainage and flood control projects. These impacts would increase the costs of capital projects and put a greater strain on an ever tightening City budget.” City of Scottsdale Comments 7, ID-18024 (JA__). In addition, through the Rule, the Agencies are asserting regulatory authority over traditionally state-regulated waters. This displacement of state authority impairs the States’ abilities to establish and enforce their own policies for their waters and lands. For example, waters that fall outside the scope of federal jurisdiction remain subject to regulation as state waters through local laws and regulations. See, e.g., N.D. Cent. Code §§ 61-28-01 et seq.; Mont. Code Ann. §§ 75-5-101 et seq.; N.M. Stat. Ann. §§ 74-6-4 et seq.; Mo. Rev. Stat. §§ 644.006 et seq.; Ark. Code Ann. §§ 8-4-101 et seq.; Tex. Water Code §§ 26.001 et seq.; Ky. Rev. Stat. §§ 224.70-100 et seq. Instead of regulating land and water within their borders to advance their own sovereign interests, the States must now defer to the federal government’s framework and policies established under the CWA. B. The Rule Exceeds Congress’s Commerce Clause Authority. The Constitution grants to Congress the power “[t]o regulate Commerce with foreign Nations, and among the several States, and with the Indian Tribes.” 64 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 75 U.S. Const. art. I, § 8, cl. 3. That power extends only to three areas: (1) “channels of interstate commerce;” (2) the “instrumentalities of interstate commerce;” and (3) “activities that substantially affect interstate commerce.” United States v. Lopez, 514 U.S. 549, 558-59 (1995). The Rule imposes federal authority outside of these areas, and thus improperly steps into the realm of the States’ regulatory authority. 1. The CWA’s protection of “navigable waters” rests entirely upon Congress’s authority to regulate the “channels of interstate commerce.” Id. As the Supreme Court explained in SWANCC, the CWA is authorized by Congress’s “traditional jurisdiction over waters that were or had been navigable-in-fact or which could reasonably be so made.’” 531 U.S. at 172; id. at 168 n.3 (finding no indication that “Congress intended to exert anything more than its commerce power over navigation”); accord Kaiser Aetna v. United States, 444 U.S. 164, 173 (1979) (“It has long been settled that Congress has extensive authority over this Nation’s waters under the Commerce Clause” as channels of interstate commerce.); Gibbons v. Ogden, 22 U.S. (9 Wheat.) 1, 189-97 (1824). This understanding of the CWA’s constitutional basis is mandated by the statutory text, which asserts jurisdiction only to protect “navigable waters,” see, e.g., 33 U.S.C. § 1362(12), and does not invoke Congress’s authority to protect instrumentalities of commerce or those matters substantially affecting interstate commerce. 65 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 76 The Rule reaches far beyond Congress’s authority to protect in-fact navigable waters; that is, those waters that can be used as channels of interstate commerce. While Congress has authority to regulate more than merely the channels themselves, regulation under this authority must be carefully limited to protecting those channels. For example, “Congress may exercise its control over the non-navigable stretches of a river in order to preserve or promote commerce on the navigable portions.” Oklahoma ex rel. Phillips v. Guy F. Atkinson Co., 313 U.S. 508, 523 (1941). But as explained above, the Rule sweeps in numerous local land and water features that are not navigable-in-fact and have only an extremely tangential, if any, connection to navigable-in-fact waters, including just once every one-hundred years. Given that the Agencies’ assertion of authority in SWANCC raised grave constitutional issues because the waters there were somewhat remote from navigable-in-fact waters, 531 U.S. at 174, the far more expansive authority over local land and water features at issue in the Rule moves from mere concern to outright constitutional violation. 2. Since the CWA is based exclusively upon Congress’s authority over channels of interstate commerce, the Agencies may not rely on the second or third—and broadest—category of activities that “substantially affect interstate commerce,” Lopez, 514 U.S. at 558-59, or the aggregation doctrine that the Court has developed and applied exclusively in the context of that third category, id. at 66 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 77 560-61. Congress has not adopted a comprehensive scheme for water and land use management, as it had for the regulation of controlled substances at issue in Gonzales v. Raich, 125 S. Ct. 2195 (2005). Instead, Congress enacted a regime tied to one specific category of waters: those that are navigable-in-fact or could reasonably be made so. Even if this Court were to analyze the Rule under Lopez’s third prong, however, the Rule would not be lawful because it allows for regulation of much more than activities that “substantially affect interstate commerce.” And in so doing, the Rule “effectually obliterate[s] the distinction between what is national and what is local,” Lopez, 514 U.S. at 557 (internal quotations omitted). Importantly, this is not a limited problem of the “de minimis character of individual instances arising under [the Rule],” Raich, 545 U.S. at 17, but rather the heart of the Rule’s reach. In both Lopez and United States v. Morrison, 529 U.S. 598 (2000), the Supreme Court rejected the federal government’s attempt to defend the constitutionality of a law regulating non-economic activities based on an argument that those non-economic activities, taken in aggregate, would have a substantial effect on interstate commerce. In Lopez, the Court determined that the law reached activity—specifically, the possession of a firearm in a school zone—that was “in no sense an economic activity.” 514 U.S. at 567. The Court rejected the argument 67 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 78 that Congress had the authority to reach this non-economic activity because, in aggregate, guns in school zones would have a substantial effect on interstate commerce. Such aggregation would involve “pil[ing] inference upon inference in a manner that would bid fair to convert congressional authority under the Commerce Clause to a general police power of the sort retained by the States.” Id. Similarly, in Morrison, the law at issue—the right to bring a civil action in federal court for domestic violence victims—targeted “noneconomic activity,” whereas every case “in our Nation’s history” that upheld Commerce Clause regulation of intrastate activity involved “activity [that was] economic in nature.” 529 U.S. at 613. As in Lopez, the federal government’s argument relied on an impermissible “but-for causal chain from the initial occurrence of violent crime . . . to every attenuated effect upon interstate commerce.” Morrison, 529 U.S. at 615. The Rule, to the extent it would be analyzed under the third prong at all, would fail for similar reasons. First, the Rule allows the Agencies to regulate non-economic activities, which Lopez and Morrison held cannot be aggregated to produce the required substantial effect on interstate commerce. As the Rapanos plurality observed, “[i]n deciding whether to grant or deny a permit, the [Corps] exercises the discretion of an enlightened despot, relying on such factors as ‘economics,’ ‘aesthetics,’ ‘recreation,’ and ‘in general, the needs and welfare of the people.’” 547 U.S. at 68 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 79 721 (Scalia, J., plurality) (quoting 33 C.F.R. § 320.4(a) (2004)). Thus, for example, the Agencies could prohibit an individual from disposing of leaves or brush in a shallow swale on his or her property provided that the swale is within 1,500 feet of the ordinary high water mark of a “tributary” to a navigable water. That is “in no sense an economic activity that might, through repetition elsewhere, substantially affect any sort of interstate commerce.” Lopez, 514 U.S. at 567. Second, the Rule fails to “express[ly] . . . limit its reach to [activities that] have an explicit connection with or effect on interstate commerce.” Id. at 562. The Rule’s definitions for tributaries, adjacent waters, and case-by-case waters sweep in numerous waters and usually-dry lands that lack any meaningful connection to interstate commerce. For example, the tributary definition extends to any land feature with “a bed and banks and an ordinary high water mark”— whether observable in the field or not—and that “contributes flow”—no matter how ephemeral—“either directly or through another water” to a primary water. 33 C.F.R. § 328.3(c)(3) (emphasis added). This includes usually-dry channels that carry a minimal amount of water after a rainstorm to a stream that connects with other streams that then eventually flow into a navigable water. The Rule’s assertion of case-by-case jurisdiction is based on an analysis that has little to nothing to do with commerce. For example, the Agencies may assert authority over a water or land because it “[e]xport[s] . . . organic matter,” 33 69 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 80 C.F.R. § 328.3(c)(5)(vii), to a primary water. In other words, if a bird flies from a primary water to another water or piece of dry land and a plant or invertebrate “hitchhik[es],” Connectivity Study 5-5, ID-20859 (JA__), on the bird’s feathers and travels back to the primary water, that would be sufficient for the Agencies to assert jurisdiction under the Rule. Or if the land feature “[e]xport[s] . . . food resources,” 33 C.F.R. § 328.3(c)(5)(viii), because a bird travels to eat, the Agencies could deem it jurisdictional under the Rule. This is precisely the kind of overreach the Supreme Court expressly rejected in SWANCC. Third, as in Lopez and Morrison, the Rule ultimately relies on an attenuated causal chain that “obliterate[s] the distinction between what is national and what is local,” Lopez, 514 U.S. at 557 (quotations omitted). In Lopez and Morrison, the Supreme Court rejected the federal government’s theory “that Congress may regulate noneconomic, violent criminal conduct based solely on that conduct’s aggregate effect on interstate commerce,” Morrison, 529 U.S. at 617. The Court explained that such reasoning would improperly permit the federal government to take over whole “areas of traditional state regulation.” Id. at 615. The same is true here, where the Rule’s overbroad assertion of authority over local land and water features tramples the States’ authority to manage local lands and waters. 70 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 81 C. The Rule Is Unconstitutionally Vague. A statute or regulation is constitutionally invalid under the Due Process Clause if it prohibits conduct “in terms so vague that men of common intelligence must necessarily guess at its meaning and differ as to its application.” Ass’n of Cleveland Fire Fighters, 502 F.3d at 551 (citing Connally v. Gen. Constr. Co., 269 U.S. 385, 391 (1926)). In Chicago v. Morales, 527 U.S. 41 (1999), for example, the Supreme Court found void for vagueness an ordinance that imposed a criminal sanction for loitering, defined as “remaining in any one [public] place with no apparent purpose,” with one or more people the police officer reasonably believes are gang members. Id. at 47 (quotations and citations omitted). The Court reasoned that it would be difficult for a person to “know if he or she had an ‘apparent purpose.’” Id. at 57. A law may be unconstitutionally vague for two independent reasons. “First, it may fail to provide the kind of notice that will enable ordinary people to understand what conduct it prohibits; second, it may authorize and even encourage arbitrary and discriminatory enforcement.” Id. at 56. Such vagueness concerns are particularly acute where, as with the CWA, the term at issue involves a criminal prohibition. See Johnson v. United States, 135 S. Ct. 2556-57 (2015); 33 U.S.C. § 1319(c). Under these standards, the Rule is unconstitutionally vague. 71 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 82 First, the Rule “fail[s] to provide the kind of notice that will enable ordinary people to understand what conduct it prohibits.” Morales, 527 U.S. at 56. For example, the Rule’s tributaries category covers any “water that contributes flow, either directly or through another water” and that is “characterized by the presence of the physical indicators of a bed and banks and an ordinary high water mark.” 33 C.F.R. § 328.3(c)(3). But as a Corps’ 2004 report explains, “selection of reliable OHWM field indicators [is] challenging” and “especially difficult in arid regions” even with respect to present channels.10 Moreover, the Agencies explain that they will use remote sensing and desktop tools to determine the OHWM and bed and banks of tributaries where “physical characteristics of bed and banks and another indicator of [OHWM] are absent in the field.” 80 Fed. Reg. at 37,077. In other words, even where there is no evidence of a bed and bank to the naked eye, the Agencies can assert jurisdiction over an indentation on the landscape that appears through sophisticated digital photography and satellite imaging to which ordinary people do not have access. See id. 10 R.W. Lichvar & J.S. Wakeley, U.S. Army Corps of Eng’rs, Review of Ordinary High Water Mark Indicators for Delineating Arid Streams in the Southwestern United States (2004), http://www.erdc.usace.army.mil/Media/Fact-Sheets/FactSheet-Article-View/Article/486085/ordinary-high-water-mark-ohwm-researchdevelopment-and-training/; see also AMA Comments 10, ID-13951 (JA__). 72 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 83 Relatedly, the Rule’s inclusion of “[d]itches with intermittent flow that are a relocated tributary, or are excavated in a tributary, or drain wetlands, [and] [d]itches, regardless of flow, that are excavated in or relocate a tributary,” 80 Fed. Reg. at 37,078, is similarly unconstitutionally vague. The Agencies explain that these ditches will be identified by the “historical presence of tributaries using a variety of resources, such as historical maps, historical aerial photographs, local surface water management plans, street maintenance data, wetlands and conservation programs and plans, as well as functional assessments and monitoring efforts.” Id. at 37,078-79. But it is exceedingly difficult under this standard for an ordinary individual to know if a ditch will be covered. Even if the individual has the capability to conduct this research, it is unclear how far back in history the individual must look for the presence of a previously existing tributary. The Rule’s case-by-case waters category presents similar problems for ordinary landowners. That category instructs the Agencies to look at any water that is “[at least partially] located within the 100-year floodplain of a” primary water or “waters [at least partially] located within 4,000 feet of the high tide line or ordinary high water mark of a” primary water, impoundment, or tributary, 33 C.F.R. § 328.3(a)(8), and then to apply a largely unguided case-by-case analysis, looking at whether the water “either alone or in combination with other similarly situated waters in the region, significantly affects the chemical, physical, or 73 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 84 biological integrity of a [primary water]” based on “any single function or combination of functions performed by the water,” id. § 328.3(c)(5) (emphasis added). Given the number of factors that staff are instructed to consider in terms of “chemical,” “physical” or “biological” impact, see, e.g., 80 Fed. Reg. at 37,093 (referencing sediment trapping, nutrient recycling, food export, flood control, and multiple other factors), it will not be possible for ordinary people to know how any particular jurisdictional inquiry will turn out under the Rule. Second, for many of the same reasons, the Rule is unconstitutionally vague because it “authorize[s] and even encourage[s] arbitrary and discriminatory enforcement.” Morales, 527 U.S. at 56. “[W]here the legislature fails to provide . . . minimal guidelines, a criminal statute may permit a standardless sweep that allows policemen, prosecutors, and juries to pursue their personal predilections.” Kolender v. Lawson, 461 U.S. 352, 358 (1983) (internal quotations omitted). The Supreme Court has concluded that a statute requiring an individual to provide “‘credible and reliable’ identification” was vague because it failed “to establish standards by which the officers may determine whether the suspect has complied.” Id. at 360-61. The Rule does not provide the Agencies’ field staffs with “minimal guidelines” for assessing whether waters are subject to the CWA. For example, with regard to the tributaries category, the Rule does not define bed and banks 74 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 85 precisely, including allowing the Agencies to arbitrarily determine that a bed and banks exist through remote imaging. Moreover, even the presence of a bed, banks, and OHWM provide insufficient restraint against arbitrary enforcement because “OHWM indicators are distributed randomly throughout the [arid west] landscape and are not related to specific channel characteristics.” AMA Comments 11, ID13951 (JA__) (quoting Lindsey Lefebvre, et al., U.S. Army Corps of Eng’rs, Survey of OHWM Indicator Distribution Patterns across Arid West Landscapes 17 (2013), http://acwc.sdp.sirsi.net/client/en_US/search/asset/1017540). And the case-by-case waters category involves the application of numerous different considerations, without clear indication of how any inquiry should turn out. In many situations, a person subject to the law has no way to know whether his or her land contains a water of the United States before an enforcement action is commenced, unless he or she requests a jurisdictional determination. And the jurisdictional determination process is not required by the CWA. Hawkes, 136 S. Ct. at 1816-17 (Kennedy, J., concurring). D. The Agencies’ Repeated Unlawful Interpretations Of “Waters Of The United States” Threaten The Constitutionality Of That Term. In Johnson v. United States, 135 S. Ct. 2551 (2015), the Supreme Court invalidated the residual clause of the Armed Career Criminal Act—“involves conduct that presents a serious potential risk of physical injury to another,” 18 U.S.C. § 924(e)(2)(B)—after several decades of attempting to give that term a 75 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 86 definite meaning. The Supreme Court explained: “the failure of persistent efforts . . . to establish a standard” under a broadly worded statutory phrase can lead the courts to declare that phrase unconstitutional. Johnson, 135 S. Ct. at 2558 (quotation omitted). The Agencies’ repeated failures to provide a lawful definition for the statutory term “waters of the United States” threaten that term’s legality. As Justice Kennedy has noted in a recent opinion joined by Justices Thomas and Alito, “the [CWA’s] reach is ‘notoriously unclear’ and the consequences to landowners . . . can be crushing.” Hawkes, 136 S. Ct. at 1816 (Kennedy, J., concurring) (quoting Sackett v. EPA, 132 S. Ct. 1367, 1375 (2012) (Alito, J., concurring)). This lack of clarity “raise[s] troubling questions regarding the Government’s power to cast doubt on the full use and enjoyment of private property throughout the Nation.” Id. at 1817. For the third time now, the Agencies have adopted an interpretation of the term “waters of the United States” that cannot withstand constitutional scrutiny, including because it is vague and “essentially limitless,” Rapanos, 547 U.S. at 757 (Roberts, C.J., concurring). The States join Chief Justice Roberts in urging the Agencies, in the strongest possible terms, to stop their repeated unlawful practice and to issue a definitional rule that ordinary people can understand and that is consistent with “the clearly limiting terms Congress employed in the Clean Water 76 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 87 Act.” Id. at 758. If the Agencies persist in their pattern of unlawful conduct, the Supreme Court may well choose to invalidate the term “waters of the United States,” just as it did with the residual clause in Johnson. IV. THE RULE VIOLATES THE NATIONAL ENVIRONMENTAL POLICY ACT. “NEPA is a procedural statute, designed to ensure that federal agencies consider the environmental impact of their actions.” Friends of Tims Ford v. Tennessee Valley Auth., 585 F.3d 955, 968 (6th Cir. 2009) (quotations and citation omitted). Unless exempted by statute, all agencies must comply with NEPA. See Pac. Legal Found. v. Andrus, 657 F.2d 829, 833 (6th Cir. 1981); 42 U.S.C. § 4332; 40 C.F.R. § 1507.1. EPA enjoys such an exemption for certain activities under the CWA, see 33 U.S.C. § 1371(c), but the Corps does not. NEPA requires the preparation of an environmental impact statement (“EIS”) for “major Federal actions significantly affecting the quality of the human environment.” 42 U.S.C. § 4332(2)(C). This includes the promulgation of federal regulations. 40 C.F.R. § 1502.4(b). As one of the most far-reaching regulations ever adopted in the environmental arena, the Rule easily qualifies as a major federal action significantly affecting the quality of the human environment. The Corps, however, elected not to prepare an EIS for the Rule, and instead issued a Finding of No Significant Impact (“FONSI”) after preparing a legally deficient Environmental 77 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 88 Assessment (“EA”).11 That finding—that the Rule has no significant impact on the human environment—is arbitrary and capricious and must be set aside. See Crounse Corp. v. I.C.C., 781 F.2d 1176, 1193 (6th Cir. 1986). The Corps also violated NEPA by evaluating an unreasonably restricted range of alternatives, considering only two—the Rule and a “no action” alternative in which the Corps would continue regulating under the existing rule and postRapanos agency guidance. The failure to consider a reasonable range of alternatives to the proposed agency action violates NEPA. Partners in Forestry Co-op., Northwood Alliance, Inc. v. U.S. Forest Serv., 638 F. App’x 456, 464-65 (6th Cir. 2015). A. The Corps Failed To Prepare An Environmental Impact Statement. The Corps’ implausible conclusion that the Rule does not significantly affect the quality of the human environment was reached without considering legallyprescribed, mandatory factors for such assessments. “NEPA’s regulations state that whether a project is ‘significant’ requires agencies to consider both the ‘context’ and the ‘intensity’ of the project.” Partners in Forestry Co-op., 638 F. App’x at 462 (quoting 40 C.F.R. § 1508.27). “Context” focuses “on the affected geographical region and its interests,” while “intensity” looks “to the severity of 11 Agencies may prepare EAs as an initial step in the NEPA process to determine whether an EIS is warranted. See 40 C.F.R. § 1508.9; Charter Twp. of Huron, Mich. v. Richards, 997 F.2d 1168, 1174 (6th Cir. 1993). 78 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 89 the proposal’s environmental impact.” Hodges v. Abraham, 300 F.3d 432, 438 (4th Cir. 2002). The Corps did not consider either the “context” or the “intensity” factors in its NEPA analysis. That alone should invalidate the Corps’ determination. See State Farm, 463 U.S. at 43 (vacatur is required if the agency “entirely failed to consider an important aspect of the problem”). In addition, both factors overwhelmingly support a finding that the Rule will significantly affect the quality of the human environment. Context. “The significance of an action must be analyzed in several contexts such as society as a whole (human, national), the affected region, the affected interests, and the locality.” 40 C.F.R. § 1508.27(a). The Rule is nationwide in scope, affecting all fifty States. In fact, it was the sweeping national effect of this regulation that partially prompted this Court to assert jurisdiction. See In re U.S. Dep’t of Def., U.S. E.P.A. Final Rule, 817 F.3d at 274. By the Agencies’ own estimates, the Rule will result in “an increase of between 2.8 and 4.6 percent in the waters found to be jurisdictional.” Final EA 21, ID-20867 (JA__). Even if these estimates were accurate, they would have profound implications on federal and state regulatory programs, private landowners, and the regulated community. For example, the Agencies have performed more than 400,000 jurisdictional determinations since 2008. 80 Fed. 79 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 90 Reg. at 37,065. Small increases in jurisdiction trigger thousands of additional federal regulatory interactions between the public and private sector each year. But the Agencies’ estimates are grossly understated, and significantly mislead the public regarding the true regulatory and economic implications of the Final Rule. For example, Kansas estimated a 460% increase in federal jurisdiction in that State alone under the Proposed Rule, with an additional 133,000 miles of ephemeral streams subject to per se jurisdiction under the new tributary definition. KS Comments App. A, ID-14794 (JA__). Alaska is concerned that the Rule will regulate “nearly all waters and wetlands” within that State. AK Gov. Comments 1, ID-19465 (JA__). So too is New Mexico. NM ED Comments 10, ID-16552 (JA__) (the Rule “would in effect engulf all streams, drainage systems, and watersheds within the State”). Ninety-six percent of Arizona’s streams “flow only part of the time or only in direct response to precipitation events,” AZ DEQ Comments 2, ID-16437 (JA__), and “approximately 80% of Wyoming’s stream miles are intermittent or ephemeral.” WY DEQ Comments 4, ID-18020 (JA__); see also KY Ag. Comm. Comments 1, ID-14055 (JA__) (expressing concern regarding 92,000 stream miles in Kentucky). The Corps simply ignored this “context” when proclaiming the Rule lacks significant effect. If the Corps had attempted to accurately quantify the actual impacts of the Rule, there is no way it could have articulated a “rational 80 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 91 connection” between these impacts and its FONSI. See Bowman Transp., 419 U.S. at 285. Indeed, as the Corps’ own staff recognizes, absent an EIS “it is not possible to estimate” or “verify” the percentage of water bodies that would be effected by the Rule, and particularly by the changes made between the Proposed Rule and Final Rule. Moyer Memorandum 2, ID-20882 (JA___). Rather, “[t]his is precisely the type of research and analysis that would be undertaken in completing an Environmental Impact Statement (EIS).” Id. at 3. The Corps also ignored the very large regional variations in the nation’s waterways when analyzing the potential effects of its Rule. For example, the Corps believes that the largest expansion of its regulatory program will likely be in the “other waters” category. Final EA 21-22, ID-20967 (JA__) (estimating a 34.5% increase in positive federal jurisdictional determinations for other waters). Geographical and hydrological features—including those covered by the “other waters category”—are not evenly distributed across the United States. See, e.g., 33 C.F.R. § 328.3(a)(7). Although the Agencies were well aware of that fact, and were reminded of it during the public comment period, see, e.g., AK DEC Comments 12, ID-19465 (JA__), they unreasonably failed to address this “context” in the EA. Instead, they relied on broad national averages to estimate the total costs and benefits associated with the Rule, marginalizing the potentially disparate treatment for individual States. See, e.g., Final EA 25, ID-20867 (JA__) (“To 81 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 92 estimate annual costs and benefits, the agencies uniformly applied the 2.8 and 4.6 percent incremental change in jurisdiction to the total costs and benefits for the Sections 311, 401, 402, . . . and 404 programs to account for an estimated increase in permitting and regulatory activities that would result.”). Intensity. The “intensity” factors also support a finding that the Final Rule “significantly” affects the human environment. These factors measure the “severity of impact” associated with a federal action, and include: (4) The degree to which the effects on the quality of the human environment are likely to be highly controversial. ... (6) The degree to which the action may establish a precedent for future actions with significant effects or represents a decision in principle about a future consideration. ... (10) Whether the action threatens a violation of Federal, State, or local law . . . . 40 C.F.R. § 1508.27(b). The EA does not discuss or address these, or any of the ten available factors, a failure that alone supports a finding of arbitrary and capricious decision-making. See State Farm, 463 U.S. at 43 (the agency “entirely failed to consider an important aspect of the problem”). Focusing on just of few of the ten factors, it is clear that the Rule rises to the level of significance that warrants full analysis in an EIS. For example, the Rule is without a doubt highly controversial. See 40 C.F.R. § 1508.27(b)(4). “Controversy in the NEPA context does not necessarily denote public opposition to 82 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 93 a proposed action, but a substantial dispute as to the size, nature, or effect of the action.” Middle Rio Grande Conservancy Dist. v. Norton, 294 F.3d 1220, 1229 (10th Cir. 2002) (wide disputes regarding the loss of farmland acreage sufficiently controversial to warrant EIS). This case is nothing if not a dispute over the “size, nature, or effect” of the Rule. This factor alone warrants the preparation of an EIS. The Rule also establishes a precedent for future actions with significant effects and represents a decision in principle about future considerations, see 40 C.F.R. § 1508.27(b)(6), because it sets controlling guidelines for hundreds of thousands of future regulatory decisions, see 80 Fed. Reg. at 37,065. Each positive jurisdictional determination rendered pursuant to the Rule will have substantial legal, economic, and environmental impacts on the property where it is made and any projects planned for that property. See Hawkes Co., 136 S. Ct. at 1814-15. Expanding federal jurisdiction necessarily increases this burden. In Hawkes, for example, the required environmental analysis for a CWA permit was estimated at $100,000, and it can be much more. Id at 1815. Finally, as already discussed, the Rule “threatens a violation of Federal, State, or local law,” 40 C.F.R. § 1508.28(b)(10), as dozens of organizations and States informed the Agencies during the public comment period on the Proposed Rule. See, e.g., Multi-State Comments 2, ID-7988 (JA__); WAC Comments 3-4, ID-14568 (JA__). Many of those same legal concerns were recognized by this 83 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 94 Court and the District Court for the District of North Dakota in temporarily staying the Final Rule. See In re EPA, 803 F.3d 804 (6th Cir. 2015); North Dakota v. U.S. EPA, 127 F. Supp. 3d 1047 (D.N.D. 2015). Taking all of these factors into consideration, there is no plausible explanation for failing to prepare an EIS in support of the Final Rule, a fatal flaw the Corps should have easily identified during the EA development process. B. The Corps Rejected The Need For An Environmental Impact Statement Based On A Flawed Environmental Assessment. The purpose of an EA is to assess the “environmental impacts of proposed actions and alternatives” to determine whether an EIS is required. Richards, 997 F.2d at 1174 (citing 40 C.F.R. § 1508.9). In making that assessment, NEPA requires “a ‘hard look’ at the environmental consequences” of agency action. Crounse Corp., 781 F.2d at 1193. “A proper consideration of the . . . impacts of a project requires some quantified or detailed information; general statements about possible effects and some risk do not constitute a hard look absent a justification regarding why more definitive information could not be provided.” KlamathSiskiyou Wildlands Ctr. v. Bureau of Land Mgmt., 387 F.3d 989, 993-94 (9th Cir. 2004) (finding an EA inadequate) (quotation omitted). The EA prepared by the Corps falls far short of the “hard look” that NEPA requires. For example, the “Environmental Consequences” section of the EA provides a brief, two-page description of how much the Rule will cause federal jurisdiction 84 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 95 to expand, but then makes no serious attempt to assess the environmental and socioeconomic effects of that new federal jurisdiction. Final EA 21-23, ID-20867 (JA__). Instead, the EA’s “analysis” of environmental consequences, comprising only four pages, has sections relating to wildlife, recreation, and flood risk reduction. Id. at 24-27 (JA__). Each of those sections contains only one or two short paragraphs, and only one sentence of analysis, each of which is conclusory and virtually identical. Those single sentences of “analysis” assert that the extension of federal jurisdiction is expected to benefit the environment, but the Corps fails to support this assertion with any evidence or effort to quantify the benefits. This is but one example: “The additional protections associated with the incremental increase in the amount of waters subject to Clean Water Act jurisdiction is expected to have a beneficial impact on recreation, based on the increase in wildlife available for hunting, fishing, bird watching, and photography.” Id. at 25 (JA__). Nowhere does the Corps describe why it believes the Rule will lead to an increase in wildlife or attempt to quantify that increase. And most importantly, the Corps fails to mention whether the States are already regulating the same waters under state law and whether the net effect of duplicative regulation would have any positive or negative effect on wildlife. This is precisely 85 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 96 the kind of drive-by analysis the courts have rejected under NEPA. See, e.g., Klamath-Siskiyou Wildlands Ctr., 387 F.3d at 996. The fundamental purpose of NEPA is to force federal agencies to genuinely consider the environmental costs and benefits of major federal actions. That purpose is thwarted here by the Corps’ refusal to make any effort to analyze or quantify the environmental, socioeconomic or other effects of its sweeping new Rule, including potential effects on the States, their regulatory programs, or their regulated communities. And the Corps’ decision to avoid preparing an EIS, based on the flawed EA, prohibited the States from participating in the NEPA process for the Rule as “cooperating agencies,” see 40 C.F.R. §§ 1501.6 and 1508.5, further eroding the cooperative federalism principles enshrined in our nation’s laws. See George T. Frampton, Memorandum for Heads of Federal Agencies: Designation of Non-Federal Agencies To Be Cooperating Agencies 2 (July 28, 1999), available at https://ceq.doe.gov/nepa/regs/ceqcoop.pdf (“Considering NEPA’s mandate and the authority granted in federal regulation to allow for cooperating agency status for state, tribal and local agencies, cooperator status for appropriate non-federal agencies should be routinely solicited.”). C. The Corps Failed To Consider A Reasonable Range Of Alternatives. The flawed EA and the resultant failure to prepare an EIS fundamentally undermined the Corps’ NEPA analysis of the Rule, but it was not the only fatal 86 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 97 defect. Agencies are required to consider alternatives to their proposed actions to fulfill the mandates of NEPA. 42 U.S.C. § 4332(2)(C)(iii). The Corps’ alternatives analysis in the EA fails any objective review of that important requirement. “An agency is required to ‘consider responsible alternatives to its chosen policy and to give a reasoned explanation for its rejection of such alternatives.’” Am. Radio Relay League, Inc. v. F.C.C., 524 F.3d 227, 242 (D.C. Cir. 2008) (citation omitted). The same holds true whether an agency is preparing an EA or an EIS. Partners in Forestry Co-op., 638 F. App’x at 464. “[T]he purpose of an EA, which is defined in regulations of the Council on Environmental Quality (CEQ) as a concise document describing the environmental impacts of proposed actions and alternatives, 40 C.F.R. § 1508.9 (1992), is to provide the agency with the basic information needed to decide on the next step.” Richards, 997 F.2d at 1174 (emphasis added). Agencies do not fulfill their obligation to consider alternatives when—as here—they artificially limit themselves to the two options of the proposed action and a no-action alternative without considering obvious variations. See Save Our Cumberland Mountains v. Kempthorne, 453 F.3d 334, 345 (6th Cir. 2006). The Corps considered only one alternative to the Rule, a “no action” alternative, where “the current procedures, processes, and definitions used by the 87 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 98 USACE to complete jurisdictional determinations would continue to be utilized and the process and procedures would not be impacted by the changes to jurisdiction with the adoption of the final proposed rule.” Final EA 23, ID-20867 (JA__). Oddly, the Corps did not consider the Proposed Rule as an option in its NEPA analysis. Apparently, the Corps “considered whether to analyze the draft rule in th[e] Environmental Assessment, but removed it from further consideration because it is no longer a viable option to accomplish the purpose and need for action.” Id. at 13 (JA__). The Corps did not explain why it was not a “viable option” except that the decision was made “upon a review of the substantive comments received during the public comment period.” Id. What is most troubling about the Corps’ limited alternatives analysis is that several other perfectly feasible alternatives were available. Many State Petitioners, for example, submitted comments favoring an alternative that would adopt a narrower definition of “waters of the United States” that would enable them to implement their own state laws and policies to protect their own lands and waters using their on-the-ground expertise—such as permitting programs that are capable of issuing necessary permits in a reasonable timeframe and at a reasonable cost. See, e.g., ND Comments 14-15, ID-15365 (JA__); TX CEQ Comments 4, ID14279 (JA__). The EA was obligated to address the alternative of limiting CWA jurisdiction to traditional navigable waterways and waters that are closely tied to 88 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 99 those waters: “continuously present, fixed bodies of water, as opposed to ordinarily dry channels through which water occasionally or intermittently flows.” Rapanos, 547 U.S. at 733 (Scalia, J., plurality). Such an approach would enable state governments to tailor their own laws and regulations more closely to the topography of their land and to make local land use decisions more responsive to the local community directly affected, while still leaving genuine interstate waterways under federal regulation. See TX CEQ Comments 4, ID-14279 (JA__); WY DEQ Comments 7, ID-18020 (JA__). Although the purpose of the rulemaking was to respond to a series of Supreme Court decisions holding that the Agencies had been using too broad a definition of “waters of the United States,” the Corps did not even consider the possibility of a narrower definition in its EA. Several commenters also suggested that instead of adopting a single, unitary definition for the entire country, separate definitions could be adopted on a regional or state-by-state basis. See, e.g., AK DEC Comments 11-12, ID-19465 (JA__); PA DOA Comments 2, ID-14465 (JA__) (“Administering a detailed and specific but ‘one-size-fits-all’ definition applicable nationwide in states with distinct surface and groundwater attributes, and extremely divergent average annual rainfall and snowmelt characteristics will be difficult, and such a rule will undermine existing state law protections.”). Separate definitions would take into account the fact that a bed and banks may be indicia of streams in the wetter parts 89 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 100 of the country, but that in other regions beds and banks are often found in bone-dry washes. Regions with extensive farmland that becomes flooded only in rare wet years, such as the northern plains, could have a definition that takes this into account. ND Comments 6, ID-15365 (JA__). And the definition of “waters of the United States” applicable to Alaska could specifically address the complications caused by widespread permafrost. AK DEC Comments 11-12, ID-19465 (JA__). Separate state or regional “waters of the United States” definitions are a perfectly reasonable and feasible alternative that should have been addressed in the EA. The Corps failed “to consider responsible alternatives to its chosen policy and to give a reasoned explanation for its rejection of such alternatives,” Am. Radio Relay League, Inc., 524 F.3d at 242. The Corps’ decision to ignore—without comment—the principle alternatives that had been advocated by the States is arbitrary, capricious and contrary to the fundamental objectives of NEPA. CONCLUSION For all the reasons articulated above, the Rule should be vacated. 90 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 101 Respectfully Submitted, Case No. 15-3799 /s/ Eric E. Murphy Michael DeWine Attorney General of Ohio Eric E. Murphy State Solicitor Peter T. Reed Deputy Solicitor 30 East Broad Street, 17th Floor Columbus, OH 43215 (614) 466-8980 eric.murphy@ ohioattorneygeneral.gov Counsel for State of Ohio /s/ Daniel P. Bock Bill Schuette Michigan Attorney General S. Peter Manning Division Chief Daniel P. Bock Assistant Attorney General Environment, Natural Resources, and Agriculture Division 525 W. Ottawa Street P.O. Box 30755 Lansing, MI 48909 (517) 373-7540 manningp@michigan.gov Counsel for State of Michigan /s/ Elizabeth P. McCarter Herbert H. Slatery III Tennessee Attorney General and Reporter Barry Turner Deputy Attorney General Elizabeth P. McCarter Senior Counsel Office of the Attorney General and Reporter Environmental Division P.O. Box 20207 Nashville, Tennessee 37202 (615) 532-2582; (615) 741-8724 fax lisa.mccarter@ag.tn.gov Counsel for State of Tennessee 91 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 102 Case No. 15-3853 /s/ Linda B. Secord Jeffrey C. Mateer First Assistant Attorney General Brantley Starr Deputy First Assistant Attorney General James E. Davis Deputy Attorney General for Civil Litigation Priscilla M. Hubenak Chief, Environmental Protection Division Linda B. Secord Assistant Attorney General Office of the Attorney General P.O. Box 12548 (MC 059) Austin, Texas 78711-2548 (512) 475-4002 linda.secord@texasattorneygeneral.gov Counsel for State of Texas /s/ Mary Jo Woods Jim Hood Attorney General of the State of Mississippi Mary Jo Woods Special Assistant Attorney General Mississippi Attorney General’s Office Post Office Box 220 Jackson, Mississippi 39205 mwood@ago.state.ms.us (601) 359-3020 Counsel for State of Mississippi 92 /s/ Steven B. “Beaux” Jones Jeff Landry Attorney General Wilbur L. “Bill” Stiles First Assistant Attorney General Steven B. “Beaux” Jones Assistant Attorney General Environmental Section Office of the Louisiana Attorney General 1885 N. Third Street Baton Rouge, Louisiana 70802 (225) 326-6085 Jonesst@ag.state.la.us Counsel for State of Louisiana Case: 15-3822 Document: 130 Case No. 15-3822 /s/ P. Clayton Eubanks E. Scott Pruitt Attorney General P. Clayton Eubanks Deputy Solicitor General 313 N.E. 21st Street Oklahoma City, OK 73105 (405) 522-8992; (405) 522-0608 fax Clayton.Eubanks@oag.ok.gov Fc.docket@oag.ok.gov Counsel for State of Oklahoma 93 Filed: 11/01/2016 Page: 103 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 104 Case No. 15-3887 /s/ Britt C. Grant Christopher M. Carr Attorney General Britt C. Grant Solicitor General Timothy A. Butler Deputy Solicitor General James D. Coots Sr. Asst. Attorney General OFFICE OF THE ATTORNEY GENERAL 40 Capitol Square, S.W. Atlanta, Georgia 30334 bgrant@law.ga.gov (404) 651-9453 Counsel for State of Georgia /s/ Elbert Lin Patrick Morrisey Attorney General Elbert Lin Solicitor General Erica N. Peterson Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL State Capitol Building 1, Rm 26-E Charleston, West Virginia 25305 Elbert.Lin@wvago.gov (304) 558-2021 Counsel for State of West Virginia /s/ Jonathan A. Glogau Pamela Jo Bondi Attorney General Jonathan L. Williams Deputy Solicitor General Jonathan A. Glogau Special Counsel OFFICE OF THE ATTORNEY GENERAL PL-01, The Capitol Tallahassee, Florida 32399-1050 Jon.glogau@myfloridalegal.com (850) 414-3300 Counsel for State of Florida /s/ Andrew Brasher Luther Strange Attorney General Andrew Brasher Solicitor General OFFICE OF THE ATTORNEY GENERAL 501 Washington Ave. Montgomery, Alabama 36130 abrasher@ago.state.al.us (334) 353-2609 Counsel for State of Alabama /s/ Thomas M. Fisher Gregory F. Zoeller Attorney General Thomas M. Fisher Solicitor General OFFICE OF THE ATTORNEY GENERAL 302 West Washington Street Indiana Government Center - South, /s/ Craig A. Bromby Sam M. Hayes General Counsel Craig A. Bromby Deputy General Counsel Andrew J. Norton Deputy General Counsel 94 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 105 NORTH CAROLINA DEPARTMENT OF ENVIRONMENT AND NATURAL RESOURCES 215 W. Jones Street Raleigh, North Carolina 27603 sam.hayes@ncdenr.gov craig.bromby@ncdenr.gov andrew.norton@ncdenr.gov (919) 707-8600 Counsel for Petitioner North Carolina Department Of Environment and Natural Resources Fifth Floor Indianapolis, Indiana 46204 (317) 232-6255 Tom.Fisher@atg.in.gov Counsel for State of Indiana /s/ Jeffrey A. Chanay Derek Schmidt Attorney General Jeffrey A. Chanay Chief Deputy Attorney General Office of the Attorney General 120 SW 10th Ave., 3d Floor Topeka, Kansas 66612 jeff.chanay@ag.ks.gov (785) 368-8435 Counsel for State of Kansas /s/ James Emory Smith Alan Wilson Attorney General Robert D. Cook Solicitor General James Emory Smith, Jr. Deputy Solicitor General OFFICE OF THE ATTORNEY GENERAL 1000 Assembly Street, Room 519 Columbia, South Carolina 29201 esmith@scag.gov (803) 734-3680 Counsel for State of South Carolina /s/ Joseph A. Newberg, II Andy Beshear Attorney General Joseph A. Newberg, II Assistant Attorney General OFFICE OF THE ATTORNEY GENERAL 700 Capitol Avenue, Suite 118 Frankfort, Kentucky 40601 Joe.newberg@ky.gov (502) 696-5650 Counsel for Commonwealth of Kentucky /s/ Parker Douglas Sean D. Reyes Attorney General Parker Douglas Chief of Staff & Federal Solicitor OFFICE OF THE UTAH ATTORNEY GENERAL Utah State Capitol Complex 350 North State Street, Suite 230 Salt Lake City, Utah 84114-2320 pdouglas@utah.gov /s/ Misha Tseytlin Brad D. Schimel Attorney General Misha Tseytlin Solicitor General Ryan J. Walsh 95 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 106 (801) 538-9600 Counsel for State of Utah Chief Deputy Solicitor General WISCONSIN DEPARTMENT OF JUSTICE 17 West Main Street Madison, Wisconsin 53707 tseytlinm@doj.state.wi.us (608) 264-6365 Counsel for State of Wisconsin 96 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 107 Case No. 15-3831 /s/ John R. Lopez IV Mark Brnovich Attorney General John R. Lopez IV Solicitor General Office of the Arizona Attorney General 1275 W. Washington St. Phoenix, AZ 85007 (602) 542–8986 John.Lopez@azag.gov Counsel for State of Arizona /s/ Paul M. Seby Wayne Stenehjem Attorney General Paul M. Seby Special Assistant Attorney General GREENBERG TRAURIG, LLP 1200 17th Street Suite 2400 Denver, CO 80202 sebyp@gtlaw.com (303) 904-6151 Jennifer L. Verleger Assistant Attorney General Office of Attorney General 500 N. 9th Street Bismarck, ND 58501 (701) 328-3640 wstenehjem@nd.gov jverleger@nd.gov Counsel for State of North Dakota /s/ J. Andrew Hirth Chris Koster Attorney General J. Andrew Hirth Deputy General Counsel PO Box 899 Jefferson City, MO 65102 (573) 751–0818 andy.hirth@ago.mo.gov Counsel for State of Missouri /s/ Frederick R. Yarger Cynthia H. Coffman Attorney General Frederick R. Yarger Solicitor General Glenn E. Roper Deputy Solicitor General COLORADO ATTORNEY GENERAL’S OFFICE 1300 Broadway, 10th Floor Denver, CO 80203 Fred.yarger@state.co.us Glenn.roper@state.co.us (720) 508-6168 Counsel for State of Colorado /s/ Chris Peloso Jahna Lindemuth Attorney General Chris Peloso Assistant Attorney General 123 Fourth Street P.O. Box 110300 Juneau, AK 99811–0300 (907) 465–6725 chris.peloso@alaska.gov Counsel for State of Alaska 97 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 108 /s/ Lara Katz Lara Katz Assistant General Counsel 1190 St. Francis Drive, Suite N4072 Santa Fe, NM 87505 (505) 827-2855 lara.katz@state.nm.us Counsel for New Mexico Environment Department /s/ Douglas M. Conde Douglas M. Conde Deputy Attorney General Office of the Attorney General Department of Environmental Quality 1410 N. Hilton, 2nd Floor Boise, ID 83706 (208) 373-0494 douglas.conde@deq.idaho.gov Counsel for State of Idaho /s/ Matthias L. Sayer Matthias L. Sayer Special Counsel 130 South Capitol Street Concha Ortiz y Pino Building P.O. Box 25102 Santa Fe, NM 57504-5102 (505) 827-6150 matthiasl.sayer@state.nm.us Counsel for New Mexico State Engineer /s/ Alan Joscelyn Tim Fox Attorney General Alan Joscelyn Chief Deputy Attorney General 215 North Sanders PO Box 201401 Helena, MT 59620-1401 (406) 444-3442 AlanJoscelyn@mt.gov Counsel for State of Montana /s/ Nicholas J. Bronni Leslie Rutledge Attorney General Nicholas J. Bronni Deputy Solicitor General Office of the Arkansas Attorney General 323 Center Street, Suite 200 Little Rock, AR 72201 (501) 682-6302 nicholas.bronni@arkansasag.gov Counsel for State of Arkansas /s/ Justin D. Lavene Douglas J. Peterson Attorney General Justin D. Lavene Assistant Attorney General Dave Bydalek Deputy Attorney General 2115 State Capitol Building PO Box 98920 Lincoln, NE 68509-8920 (402) 471-2682 justin.lavene@nebraska.gov Counsel for State of Nebraska 98 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 109 /s/ Erik Petersen Peter K. Michael Attorney General Erik Petersen Senior Assistant Attorney General James Kaste Deputy Attorney General Wyoming Attorney General’s Office 2320 Capitol Ave. Cheyenne, WY 82002 (307) 777-6946 erik.petersen@wyo.gov james.kaste@wyo.gov Counsel for State of Wyoming /s/ Lawrence VanDyke Adam Paul Laxalt Attorney General Lawrence VanDyke Solicitor General Office of the Attorney General 100 N. Carson Street Carson City, NV 89701 (775) 684-1100 LVanDyke@ag.nv.gov Counsel for State of Nevada /s/ Charles D. McGuigan Marty Jackley Attorney General Charles McGuigan Chief Deputy Attorney General Office of the Attorney General 1302 E. Highway 14, Suite 1 Pierre, SD 57501-8501 (605) 773-3215 Charles.McGuigan@state.sd.us Counsel for State of South Dakota 99 Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 110 CERTIFICATE OF COMPLIANCE This brief complies with the type-volume limitation of Fed. R. App. P. 32(a)(7)(B) because the brief contains 20,939 words, excluding the parts of the brief exempted by Fed. R. App. P. 32(a)(7)(B)(iii). By order of this Court, State Petitioners’ Opening Brief was not to exceed 21,000 words. This brief complies with the typeface requirements of Fed. R. App. P. 32(a)(5) and the type style requirements of Fed. R. App. P. 32(a)(6) because this brief has been prepared in a proportionally spaced typeface using Microsoft Word 2010 in Times New Roman font size 14. Date: November 1, 2016 /s/ Eric E. Murphy Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 111 CERTIFICATE OF SERVICE I hereby certify that on November 1, 2016, a true and correct copy of the State Petitioner’s Opening Brief was served via the Court’s CM/ECF system to the parties registered to receive notice of the filings in this case. /s/ Eric E. Murphy Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 112 Case No. 15-3751 (and related cases: 15-3799; 15-3817; 15-3820; 15-3822; 153823; 15-3831; 15-3837; 15-3839; 15-3850; 15-3853; 15-3858; 15-3885; 15-3887; 15-3948; 15-4159; 15-4162; 15-4188; 15-4211; 15-4234; 15-4305; 15-4404) IN THE UNITED STATES COURT OF APPEALS FOR THE SIXTH CIRCUIT MURRAY ENERGY CORPORATION, et al., Petitioners, v. U.S. ENVIRONMENTAL PROTECTION AGENCY, et al., Respondents. ) ) ) ) ) ) ) ) ) ) ) ) ) In Re: Environmental Protection Agency and Department of Defense, Final Rule: Clean Water Rule: Definition of “Waters of the United States,” 80 Fed. Reg. 37,054, published June 29, 2015 (MCP No. 135) On petition for review from the Environmental Protection Agency and the U.S. Army Corps of Engineers ADDENDUM PURSUANT TO FEDERAL RULE OF APPELLATE PROCEDURE 28(f) TO STATE PETITIONERS’ OPENING BRIEF Michael DeWine ATTORNEY GENERAL OF OHIO Eric E. Murphy State Solicitor Counsel of Record Peter T. Reed Deputy Solicitor Date: November 1, 2016 Office of the Attorney General 30 E. Broad Street, 17th Floor Columbus, OH 43215 Tel: (614) 466-8980 eric.murphy@ ohioattorneygeneral.gov Counsel for Petitioner State of Ohio Additional counsel listed at end of State Petitioners’ Opening Brief Case: 15-3822 Document: 130 Filed: 11/01/2016 Page: 113 TABLE OF CONTENTS Statutes: 33 U.S.C. § 1251........................................................................................... ADD-01 33 U.S.C. § 1313........................................................................................... ADD-06 33 U.S.C. § 1319........................................................................................... ADD-10 33 U.S.C. § 1342........................................................................................... ADD-17 33 U.S.C. § 1344........................................................................................... ADD-25 33 U.S.C. § 1362........................................................................................... ADD-32 33 U.S.C. § 1371........................................................................................... ADD-35 42 U.S.C. § 4332........................................................................................... ADD-36 Regulations: 33 C.F.R. Part 328; 40 C.F.R. Parts 110, 112, 116, 117, 122, 230, 232, 300, 301, and 401.......................................................................................... ADD-39 Case: 15-3822 s +,/+! Document: 130 NCNF?! 11}H;PCA;NCIH! ;H>! 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Xep! gfik`fe! f]! k_\!_`^_!j\Xj!Y\pfe[!k_\!Zfek`^lflj!qfe\,! &//'!N_\!k\id!WW\]]cl\ek!c`d`kXk`fe%%!d\Xej!Xep! i\jki`Zk`fe!\jkXYc`j_\[!Yp!X!MkXk\!fi!k_\!;[d`e+ `jkiXkfi!fe!hlXek`k`\j*!iXk\j*!Xe[!ZfeZ\ekiXk`fej! f]!Z_\d`ZXc*!g_pj`ZXc*!Y`fcf^`ZXc*!Xe[!fk_\i!Zfe+ jk`kl\ekj! n_`Z_! Xi\! [`jZ_Xi^\[! ]ifd! gf`ek! jfliZ\j!`ekf!eXm`^XYc\!nXk\ij*!k_\!nXk\ij!f]!k_\! Zfek`^lflj! qfe\*! fi! k_\! fZ\Xe*! `eZcl[`e^! jZ_\[+ lc\j!f]!Zfdgc`XeZ\,! ADD-32 Case: 15-3822 s +-0,! Document: 130 Filed: 11/01/2016 Page: 146 NCNF?! 11}H;PCA;NCIH! ;H>! H;PCA;`m`j`fe! >}GXel]XZkli`e^%%! Xe[! jlZ_!fk_\i!ZcXjj\j!f]!j`^e`]`ZXek!nXjk\!gif[lZ\ij! Xj*! Yp! i\^lcXk`fe*! k_\! ;[d`e`jkiXkfi! [\\dj! Xg+ gifgi`Xk\,! &/7'! N_\! k\id! WWgfcclk`fe%%! d\Xej! k_\! dXe+! dX[\! fi! dXe+`e[lZ\[! Xck\iXk`fe! f]! k_\! Z_\d`+ ZXc*! g_pj`ZXc*! Y`fcf^`ZXc*! Xe[! iX[`fcf^`ZXc! `ek\^+ i`kp!f]!nXk\i,! &0.'! N_\! k\id! WWd\[`ZXc! nXjk\%%! d\Xej! `jfcX+ k`fe!nXjk\j9!`e]\Zk`flj!X^\ekj9!_ldXe!Ycff[!Xe[! 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JlY,! F,! /.7z36*! k`kc\! CCC*! x 101*! ;l^,! 6*! 0..3*! //7! MkXk,! 4729! JlY,! F,! //.z066*! x 1*! Dlcp! 07*! 0..6*! /00! MkXk,!043.9!JlY,!F,!//1z/0/*!k`kc\!P*!x 3./0&Y'*!Dle\! /.*!0./2*!/06!MkXk,!/106,'! ;G?H>G?HNM ! 0./2}JXi,!&04',!JlY,!F,!//1z/0/!X[[\[!gXi,!&04',! ADD-33 Case: 15-3822 JX^\! 3.7! Document: 130 Filed: 11/01/2016 Page: 147 NCNF?! 11}H;PCA;NCIH! ;H>! H;PCA;;N? I@ 0./2! ;G?H>G?HN! ;d\e[d\ek! Yp! JlY,! F,! //1z/0/! \]]\Zk`m\! IZk,! /*! 0./2*! j\\! j\Zk`fe! 3./0&Z'! f]! JlY,! F,! //1z/0/*! j\k! flk! Xj! X! efk\! le[\i!j\Zk`fe!/070!f]!k_`j!k`kc\,! N?LGCH;NCIH I@ NLOMN N?LLCNILS I@ NB? J;=C@C=! CMF;H>M! @fi!k\id`eXk`fe! f]!Niljk! N\ii`kfip!f]!k_\! JXZ`]`Z! Cj+ cXe[j*! j\\! efk\! j\k! flk! gi\Z\[`e^! j\Zk`fe! /46/! f]! N`kc\! 26*!N\ii`kfi`\j!Xe[!CejlcXi!Jfjj\jj`fej,! N?LLCNILC;F M?; ;H> =IHNCAOIOM TIH? I@ OHCN?>! MN;N?M! @fi! \ok\ej`fe! f]! k\ii`kfi`Xc! j\X! Xe[! 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Document: 130 29<5;!Lwp!37-!3126 Lmv!346112 )x*!qh!vjku!ugevkqp-!kpenwfkpi!ygvncpfu-! rqpfu-!ncmgu-!qzdqyu-!korqwpfogpvu-! cpf!ukoknct!ycvgtu=! )xkk*!Cnn!ycvgtu!kp!rctcitcrju! )k*)2*)xkk*)C*!vjtqwij!)G*!qh!vjku!ugevkqp! yjgtg!vjg{!ctg!fgvgtokpgf-!qp!c!ecug.! urgekhke!dcuku-!vq!jcxg!c!ukipkhkecpv! pgzwu!vq!c!ycvgt!kfgpvkhkgf!kp! rctcitcrju!)k*)2*)k*!vjtqwij!)kkk*!qh!vjku! ugevkqp/!Vjg!ycvgtu!kfgpvkhkgf!kp!gcej!qh! rctcitcrju!)k*)2*)xkk*)C*!vjtqwij!)G*!qh! vjku!ugevkqp!ctg!ukoknctn{!ukvwcvgf!cpf! ujcnn!dg!eqodkpgf-!hqt!rwtrqugu!qh!c! ukipkhkecpv!pgzwu!cpcn{uku-!kp!vjg! ycvgtujgf!vjcv!ftckpu!vq!vjg!pgctguv! ycvgt!kfgpvkhkgf!kp!rctcitcrju!)k*)2*)k*! vjtqwij!)kkk*!qh!vjku!ugevkqp/!Ycvgtu! kfgpvkhkgf!kp!vjku!rctcitcrj!ujcnn!pqv!dg! eqodkpgf!ykvj!ycvgtu!kfgpvkhkgf!kp! rctcitcrj!)k*)2*)xk*!qh!vjku!ugevkqp!yjgp! rgthqtokpi!c!ukipkhkecpv!pgzwu!cpcn{uku/! 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