158 FERC ¶ 61,145 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners: Cheryl A. LaFleur, Acting Chairman; Norman C. Bay, and Colette D. Honorable. National Fuel Gas Supply Corporation Empire Pipeline, Inc. Docket Nos. CP15-115-000 CP15-115-001 ORDER GRANTING ABANDONMENT AND ISSUING CERTIFICATES (Issued February 3, 2017) 1. Pursuant to sections 7(b) and 7(c) of the Natural Gas Act (NGA) 1 and Part 157 of the Commission’s regulations, 2 on March 17, 2015, National Fuel Gas Supply Corporation and Empire Pipeline, Inc. (Empire), filed a joint application for a certificate of public convenience and necessity to construct and operate approximately 99 miles of pipeline, new and modified compression facilities, and ancillary facilities in McKean County, Pennsylvania, and Allegany, Cattaraugus, Erie, and Niagara Counties, New York. 3 National Fuel Supply Corporation also proposes to abandon 3.09 miles of pipeline by sale to Empire. These proposals compose the Northern Access 2016 Project. The purpose of the project is to expand firm service on National Fuel Supply Corporation’s system by 497,000 dekatherms (Dth) per day and to expand firm service on Empire’s system by 350,000 Dth per day. 2. For the reasons discussed below, the Commission will grant the requested certificate authorizations, subject to the conditions described herein. 1 15 U.S.C. § 717f(b), (c) (2012). 2 18 C.F.R. pt. 157 (2016). 3 On November 2, 2015, National Fuel Supply Corporation and Empire amended the application to propose a different site for a new compressor station as further discussed herein. Docket Nos. CP15-115-000 and CP15-115-001 I. -2- Background 3. National Fuel Gas Company is a vertically integrated company with several subsidiaries. These include transporters National Fuel Supply Corporation (National Fuel) and Empire, producer Seneca Resources Corporation (Seneca Resources), and gatherer NFG Midstream Clermont, L.L.C. (NGF Midstream). 4. National Fuel, a corporation organized and existing under the laws of the Commonwealth of Pennsylvania, is a natural gas company as defined by section 2(6) of the NGA. 4 National Fuel transports and stores natural gas in New York and Pennsylvania. 5. Empire, a corporation organized and existing under the laws of the State of New York, is a natural gas company as defined by section 2(6) of the NGA. 5 Empire owns a pipeline system extending from near Syracuse, New York, in the east to the United States-Canada border at Grand Island, New York, in the west, with an arm extending south from near Rochester, New York, into north central Pennsylvania. 6 A. National Fuel’s Proposal 6. National Fuel proposes to construct and operate new pipeline, compression, and appurtenant facilities in McKean County, Pennsylvania, and Allegany, Cattaraugus, Erie, and Niagara Counties, New York. The proposed facilities will enable National Fuel to provide 497,000 Dth per day of new firm transportation service from a new receipt point in Sergeant Township, McKean County, Pennsylvania, to interconnections with Empire and Tennessee Gas Pipeline Company (Tennessee) to the north and to an interconnection with Transcontinental Gas Pipe Line Company, LLC, (Transco) to the south. 7. To provide the incremental service, National Fuel proposes to construct and operate the following facilities: • • an interconnection with NFG Midstream, in McKean County, Pennsylvania; a 96.49-mile, 24-inch-diameter pipeline extending from the new 4 15 U.S.C. § 717a(6) (2012). 5 Id. § 717a(6). 6 Empire has no employees of its own. National Fuel operates Empire’s pipeline system pursuant to an Operating and Maintenance Agreement dated February 6, 2003. Docket Nos. CP15-115-000 and CP15-115-001 -3- interconnection with NFG Midstream and crossing McKean County, Pennsylvania, and Alleghany, Cattaraugus, and Erie Counties, New York (Mainline pipeline) to reach a new metering and regulation station and tiein at Tennessee’s 200 Line in the town of Wales, Erie County, New York; • a metering and regulation station and tie-in along the Mainline pipeline at National Fuel’s existing Hinsdale Compressor Station in Cattaraugus County, New York; • two additional reciprocating gas-fired compressor units rated at a combined 5,350 horsepower (hp) at National Fuel’s existing 600-hp Porterville Compressor Station in the town of Elma, Erie County, New York; • a meter and regulator/pressure reduction station on the Mainline pipeline within the site of the Porterville Compressor Station; • a tie-in between the Mainline pipeline and National Fuel’s existing Line XNorth within the site of the Porterville Compressor Station; and • 13 mainline valve sites, cathodic protection, and other auxiliary facilities to be constructed under section 2.55(a) of the Commission’s regulations. 7 National Fuel estimates the total cost of its proposed facilities to be $376,670,388. 8. National Fuel proposes to abandon 1.08 miles of its existing Line XM-10 pipeline in Niagara County, New York, by sale to Empire. This pipeline will be renamed Line EMP-03. National Fuel and Empire both propose to abandon their existing Pendleton Meter and Regulator Station on the existing Line XM-10 pipeline. They propose to remove all existing aboveground facilities and to restore the meter station site. 9. In addition, National Fuel has reserved 86,936 Dth per day of capacity on its existing Line X system from the Hinsdale Compressor Station to its Leidy Interconnection with Transco for Northern Access 2016 Project service that would begin on November 1, 2018. 10. Prior to holding an open season for the project, National Fuel executed a precedent agreement with its producer affiliate Seneca Resources for the entire 497,000 Dth per day of firm transportation service. Based on this precedent agreement, National Fuel held a binding open season for the Northern Access 2016 Project from June 3 to June 26, 2014. National Fuel offered south-to-north expansion service for a minimum term of 15 years from McKean County, Pennsylvania, to Empire’s system at the Pendleton Compressor Station. National Fuel also solicited offers to turn back firm capacity. National Fuel 7 18 C.F.R. § 2.55(a) (2016). Docket Nos. CP15-115-000 and CP15-115-001 -4- received no additional bids for transportation service and no offers to turn back existing firm capacity. 11. National Fuel and Seneca Resources subsequently entered into an Amended and Restated Precedent Agreement under which National Fuel will receive gas from Seneca Resources at a new receipt point with NFG Midstream, in McKean County, Pennsylvania, and will deliver the gas to three delivery points. The primary delivery point for 357,000 Dth per day of firm transportation service will be the proposed interconnection with Empire at the Pendleton Compressor Station in Niagara County, New York. The primary delivery point for the remaining 140,000 Dth per day of firm transportation service will be the proposed interconnection with Tennessee’s 200 Line in Erie County, New York. 12. Seneca Resources has also requested that the latter delivery point be moved on November 1, 2018, from Tennessee’s 200 Line to National Fuel’s existing interconnection with Transco’s pipeline system at Leidy in Potter County, Pennsylvania. 13. National Fuel proposes to establish incremental recourse rates under its Rate Schedules FT/FT-S, EFT, and FST for firm service using the project’s expansion capacity. B. Empire’s Proposal 14. Empire proposes to construct and operate new pipeline, compression, and appurtenant facilities in Niagara County, New York. The proposed facilities will enable Empire to provide 350,000 Dth per day of new firm transportation service from a new interconnection with National Fuel in the Town of Wheatfield, Niagara County, New York, to a delivery point with TransCanada Pipelines Limited (TransCanada) in Chippawa, Ontario (across from Grand Island, New York), or to Empire’s local distribution market in upstate New York. 15. To provide the new service, Empire proposes to acquire from National Fuel the 1.08 miles of Line XM-10 mentioned above, to be renamed Line EMP-03. Empire further proposes to construct and operate the following facilities: Docket Nos. CP15-115-000 and CP15-115-001 -5- • the 22,214-hp Pendleton Compressor Station in Niagara County, New York, composed of two 11,107-hp gas-fired, turbine-powered centrifugal compressor packages, with odorization, metering, and other appurtenant facilities; • a tie-in and 1.17-mile, 24-inch-diameter pipeline (added to Empire’s acquired line EMP-03) extending from National Fuel’s existing Line X-North into Empire’s proposed Pendleton Compressor Station, all in Niagara County, New York; • a 0.90-mile, 16-inch-diameter pipeline (also added to line EMP-03) extending from Empire’s proposed Pendleton Compressor Station to a modified tie-in with Empire’s existing mainline, all in Niagara County, New York; • various appurtenant facilities to be installed under section 2.55(a) of the Commission’s regulations at the proposed Pendleton Compressor Station; • the Wheatfield Dehydration Facility in Niagara County, New York composed of triethylene glycol dehydrators and approximately 400 feet of 24-inch-diameter inlet pipeline and a mainline valve; Empire estimates the total cost of its proposed facilities to be $78,710,359. 16. Prior to holding an open season for the project, Empire executed a precedent agreement with Seneca Resources for the entire 350,000 Dth per day of firm transportation service from the Wheatfield Interconnection with National Fuel to the interconnection with TransCanada at Chippawa, Ontario. Based on this precedent agreement, Empire held a binding open season from June 3 to June 26, 2014. Empire offered south-to-north expansion service for a minimum term of 15 years from near Pendleton in Niagara County, New York, to TransCanada at Chippawa, Ontario. Empire determined that no currently contracted firm transportation capacity could be turned back to eliminate the need for portions of the proposed project facilities. Empire received no additional bids for service. 17. Empire proposes to use its existing rates under Rate Schedule “FT – Original Empire Pipeline” as the recourse rates for firm service using the project facilities. Empire also proposes to revise its tariff to ensure that fuel consumed at the Pendleton Compressor Station will be allocated to shippers in proportion to the quantities scheduled for receipt at the Wheatfield Interconnection with National Fuel or any interconnection along acquired Line EMP-03. Empire requests a finding supporting a presumption of rolled-in rate treatment in a future section 4 rate proceeding for the costs of constructing and operating the proposed facilities. Docket Nos. CP15-115-000 and CP15-115-001 II. -6- Procedural Matters 18. Notice of the joint application was issued on March 27, 2015, with interventions, protests, and comments due April 17, 2015. 8 The parties listed in Appendix A filed timely, unopposed motions to intervene. Timely, unopposed motions to intervene are granted by operation of Rule 214 of the Commission’s rules of Practice and Procedure. 9 On May 4, 2015, National Fuel and Empire filed a motion for leave to answer protests by intervenors Allegheny Defense Project and Pennsylvania Alliance for Clean Water and Air. The Commission’s Rules of Practice and Procedure do not permit answers to protests unless otherwise ordered by the decisional authority. 10 Because the answer does not provide information that will assist the Commission in addressing the issues in this proceeding, the motion is rejected. 19. On November 2, 2015, National Fuel and Empire filed an amendment to their application to describe the revised preferred location for the Pendleton Compressor Station at the Killian Road site in the Town of Pendleton, Niagara County, New York. The amendment also revised the lengths of inlet and outlet pipelines at the Pendleton Compressor Station and reduced the length of abandoned Line XM-10, as reflected in the description of facilities above. Notice of the amendment was issued on November 4, 2015, with interventions, protests, and comments due November 25, 2015. 11 The parties listed in Appendix A filed timely, unopposed motions to intervene. Timely, unopposed motions to intervene are granted by operation of Rule 214 of the Commission’s rules of Practice and Procedure. 12 20. Kim Alianello, Michael Alianello, Buffalo Niagara Riverkeeper, David A. Byers, Sue Chris Carillo, Monica Daigler, Gina Darlak, the Sierra Club, Betty C. Skrzypek, Diana Strablow, J. Whittington, and L. Whittington filed untimely motions to intervene. On October 11, 2016, National Fuel and Empire filed an answer opposing Sierra Club’s untimely motion to intervene. We will grant the untimely motions to intervene. 13 8 80 Fed. Reg. 18,392 (Apr. 6, 2015). 9 18 C.F.R. § 385.214(c) (2016). 10 Id. § 385.213(a)(2). 11 80 Fed. Reg. 69,958 (Nov. 12, 2015). 12 18 C.F.R. § 385.214(c) (2016). 13 Id. § 385.214(d). Docket Nos. CP15-115-000 and CP15-115-001 III. -7- Discussion 21. Since National Fuel’s and Empire’s proposal includes the abandonment of existing facilities and the construction and operation of new facilities to transport natural gas in interstate commerce, subject to the jurisdiction of the Commission, the proposal is subject to the requirements of subsections (b), (c), and (e) of section 7 of the NGA. 14 A. Abandonment 22. Section 7(b) of the NGA allows a natural gas pipeline company to abandon jurisdictional facilities or services only if the abandonment is permitted by the “present or future public convenience or necessity.” 15 In deciding whether a proposed abandonment is warranted, the Commission considers all relevant factors, but the criteria vary as the circumstances of the abandonment proposal vary. When a pipeline proposes to abandon facilities, the continuity and stability of existing services are the primary considerations in assessing whether the public convenience or necessity permit the abandonment. 16 If the Commission finds that a pipeline's proposed abandonment will not jeopardize continuity of existing gas transportation services, it will defer to the pipeline's business judgment. 17 23. The applicants explain that National Fuel’s proposed abandonment of 1.08 miles of its Line XM-10 by sale to Empire, as well as both applicants’ proposal to abandon and remove their existing Pendleton Meter and Regulator Station on Line XM-10, will have no impact on the services provided to existing National Fuel or Empire customers because the applicants are simply moving the point at which National Fuel and Empire’s facilities interconnect. 18 Thus, we conclude that the proposed abandonment is permitted by the public convenience or necessity. 14 15 U.S.C. § 717f(b), (c), (e) (2012). 15 Id. § 717f(b). 16 See, e.g., El Paso Natural Gas Co., 148 FERC ¶ 61,226, at P 12 (2014) (citations omitted). 17 See, e.g., Transwestern Pipeline Co., L.L.C., 140 FERC ¶ 61,147, at P13 (2012) (citing Trunkline Gas Co., 94 FERC ¶ 61,381, at 62,420 (2001)). 18 March 17, 2015 Application at 8-9. The November 11, 2015 amended application reduced the scope of the abandonment as a result of the new location for the Pendleton Compressor Station. See November 11, 2015 Amended Application at 11-12. Docket Nos. CP15-115-000 and CP15-115-001 B. -8- Certificate Policy Statement 24. The Certificate Policy Statement provides guidance for evaluating proposals to certificate new construction. 19 The Certificate Policy Statement establishes criteria for determining whether there is a need for a proposed project and whether the proposed project will serve the public interest. The Certificate Policy Statement explains that in deciding whether to authorize the construction of major new pipeline facilities, the Commission balances the public benefits against the potential adverse consequences. The Commission’s goal is to give appropriate consideration to the enhancement of competitive transportation alternatives, the possibility of overbuilding, subsidization by existing customers, the applicant’s responsibility for unsubscribed capacity, the avoidance of unnecessary disruptions of the environment, and the unneeded exercise of eminent domain. 25. Under this policy, the threshold requirement for existing pipelines proposing new projects is that the pipeline must be prepared to financially support the project without relying on subsidization from existing customers. The next step is to determine whether the applicant has made efforts to eliminate or minimize any adverse effects the project might have on the applicant’s existing customers, identify any adverse impacts the applicant’s proposal might have on other existing pipelines in the market and their captive customers, and consider whether the applicant’s proposal would result in the unnecessary exercise of eminent domain or have other adverse economic impacts on landowners and communities affected by the route of the new facilities. If residual adverse effects on these interest groups are identified after efforts have been made to minimize them, the Commission will evaluate the project by balancing the evidence of public benefits to be achieved against the residual adverse effects. This is essentially an economic test. Only when the benefits outweigh the adverse effects on economic interests will the Commission proceed to complete the environmental analysis where other interests are considered. 26. As discussed above, the threshold requirement for companies proposing new projects is that the company must be prepared to financially support the project without relying on subsidization from its existing customers. The Commission has determined, in general, that where a company proposes to charge incremental rates for new construction, the company satisfies the threshold requirement that the project will not be subsidized by existing shippers. National Fuel proposes an incremental recourse reservation rate for firm service using the capacity created by its proposed facilities as part of the 19 Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC ¶ 61,227 (1999), order on clarification, 90 FERC ¶ 61,128, order on clarification, 92 FERC ¶ 61,094 (2000) (Certificate Policy Statement). Docket Nos. CP15-115-000 and CP15-115-001 -9- Northern Access 2016 Project. Its proposed incremental rate is designed to recover the full cost of the expansion and is higher than the applicable system rate. Therefore, we find that National Fuel’s existing shippers will not subsidize the expansion project. 27. Empire proposes to use its existing system rates as recourse rates for firm service using the capacity created by its proposed facilities as part of the Northern Access 2016 project. As discussed below, Empire has shown that the incremental revenue from Seneca Resources from firm service under negotiated rates would exceed the incremental cost of constructing and operating these proposed facilities. Accordingly, we find that Empire’s existing customers will not subsidize the project. 28. Next, we find that the project will not adversely affect National Fuel’s or Empire’s existing customers, or other pipelines and their customers. The proposed expansion facilities are designed to provide incremental service without degradation of service to National Fuel’s or Empire’s existing firm customers. 29. In addition, the project is designed to meet new demand, and there is no evidence that service on other pipelines will be displaced. No pipeline companies or their customers have objected to the project. 30. We also find that the Northern Access 2016 Project will have limited impacts on landowners and surrounding communities. Approximately 69 percent of the proposed 96.5-mile mainline pipeline will be co-located with existing pipeline and powerline rights-of-way. Maximizing the use of these previously disturbed rights-of-way will minimize both the number of landowners from which new right-of-way will need to be acquired and the potential need for reliance on eminent domain. Also, Empire responded to concerns raised by community stakeholders about the initial preferred location for the proposed Pendleton Compressor Station by later securing an option to purchase an alternative parcel within an industrially zoned area of the Town of Pendleton, New York. In view of these considerations, we find that the proposed project has been designed to minimize the impacts on landowners and communities. 31. Commenters question the need for the Northern Access 2016 Project because much of the project’s incremental firm service will be used to transport gas to Canada. Commenters state that the project is calculated only to benefit Seneca Resources’ shareholders and that the project imposes burdens on the U.S. public without providing proportional benefits to U.S. consumers. 32. All of the proposed project capacity has been subscribed under a long-term contract with Seneca Resources, demonstrating the existence of market demand for the Docket Nos. CP15-115-000 and CP15-115-001 - 10 - project. 20 Of the total incremental firm service, 140,000 Dth per day (28 percent) will be delivered into Tennessee’s system for delivery into markets in the northeastern U.S. The remaining 357,000 will be carried over Empire’s system for intended delivery into Canada, but with the option for delivery along Empire’s system in northern and central New York. The Commission does not have jurisdiction over the exportation or importation of natural gas. Such jurisdiction resides with the U.S. Department of Energy (DOE), which must act on any applications for natural gas export or import authority. 21 We note that there is no proposal before us to increase the export capacity of Empire’s facilities. The Commission’s public convenience and necessity standard includes all 20 The Commission has stated that service commitments for new capacity constitute important evidence of demand for a project. Certificate Policy Statement, 88 FERC at 61,748. See, e.g., Turtle Bayou Gas Storage Co., LLC, 135 FERC ¶ 61,233, at P 33 (2011), which found that the applicant had not sufficiently demonstrated the need for its particular project where the applicant did not conduct an open season or submit precedent or service agreements for the project’s capacity and provided only vague and generalized evidence of need for natural gas at the regional and national level. 21 Section 3(a) of the NGA provides, in part, that “no person shall export any natural gas from the United States to a foreign country or import any natural gas from a foreign country without first having secured an order of the Commission authorizing it to do so.” 15 U.S.C. § 717b(a) (2012). In 1977, the Department of Energy Organization Act transferred the regulatory functions of section 3 of the NGA to the Secretary of Energy. 42 U.S.C. § 7151(b) (2012). Subsequently, the Secretary of Energy delegated to the Commission authority to “[a]pprove or disapprove the construction and operation of particular facilities, the site at which such facilities shall be located, and with respect to natural gas that involves the construction of new domestic facilities, the place of entry for imports or exit for exports.” DOE Delegation Order No. 00-004.00A (effective May 16, 2006). The proposed facilities are not located at a potential site of exit for natural gas exports. Moreover, the Secretary of Energy has not delegated to the Commission any authority to approve or disapprove the import or export of the commodity itself, or to consider whether the exportation or importation of natural gas is consistent with the public interest. See Corpus Christi Liquefaction, LLC, 149 FERC ¶ 61,283, at P 20 (2014) (Corpus Christi). See also National Steel Corp., 45 FERC ¶ 61,100, at 61,332-33 (1988) (observing that DOE, “pursuant to its exclusive jurisdiction, has approved the importation with respect to every aspect of it except the point of importation” and that the “Commission's authority in this matter is limited to consideration of the place of importation, which necessarily includes the technical and environmental aspects of any related facilities”). Docket Nos. CP15-115-000 and CP15-115-001 - 11 - factors bearing on the public interest. 22 The Northern Access 2016 Project will provide benefits to all sectors of the natural gas market by providing producers access to multiple markets throughout the United States and Canada and increasing the diversity of supply to consumers in those markets. Based on the benefits that the proposed Northern Access 2016 Project will provide; the lack of adverse effects on existing customers, other pipelines, and their captive customers; and the minimal adverse effects on landowners or communities, we find that National Fuel’s and Empire’s proposed project is consistent with the Certificate Policy Statement. Based on this finding and the environmental review for the proposed project, as discussed below, we further find that the public convenience and necessity require approval and certification of the project under section 7 of the NGA, subject to the environmental and other conditions in this order. C. Rates and Tariff Provisions 33. National Fuel proposes to charge an initial incremental recourse rate under Rate Schedules FT/FT-S, 23 FST, and EFT for service using incremental capacity created by the Northern Access 2016 Project. Empire proposes to charge as its initial recourse rate the existing system rate under its Rate Schedule “FT-Original Empire Pipeline.” Empire requests a pre-determination to roll-in the costs associated with its portion of the project in its next NGA section 4 general rate proceeding. 34. National Fuel and Empire entered into long-term firm transportation service agreements with Seneca Resources for the maximum daily transportation quantities of 497,000 and 350,000 Dth per day, respectively. Under its agreement with National Fuel, Seneca Resources will pay the incremental recourse rates. Under its agreement with Empire, Seneca Resources will pay negotiated rates. 35. National Fuel and Empire propose various conforming revisions to their pro forma tariffs. Additionally, National Fuel requests a limited waiver of GT&C section 31.1 of its tariff so that National Fuel can accept a request from Seneca Resources to change the primary delivery point for a portion of its subscribed capacity two years after the proposed in-service date of the project. 22 23 Atlantic Refining Co. v. Pub. Serv. Comm’n of N.Y., 360 U.S. 378, 391 (1959). Rate Schedule FT-S applies to seasonal point-to-point firm transportation using capacity that is available only during certain months of the year or that varies in available amount from month-to-month during the requested term. Docket Nos. CP15-115-000 and CP15-115-001 1. - 12 - National Fuel a. Initial Rates 36. National Fuel proposes an incremental recourse rate under Rate Schedules FT/FTS, EFT, and FST 24 based on a three-year levelized incremental cost of service of approximately $67,960,440 and a design capacity of 497,000 Dth per day. The proposed cost of service is based on a depreciation rate of 1.79 percent, along with interest expenses, capital structure, return on equity, and income taxes as provided in National Fuel’s last approved rate case settlement in Docket No. RP12-88-000. 25 National Fuel proposes an initial monthly reservation rate of $11.3951 per Dth and proposes to charge no initial commodity rate. 37. The process of ratemaking occurs in several steps: functionalizing the cost of service; classifying the cost of service between fixed and variable costs; allocating costs to customer classes and/or zones; and finally designing the rate. 26 24 While individual service agreements for project service will reflect one of three rate schedule designations (FT/FTS-NA2016, EFT-NA2016, or FST-NA2016), National Fuel states that the same incremental recourse rates will apply to service under each of these rate schedules. National Fuel November 2, 2015 Amendment to Joint Abbreviated Application, Revised Ex. P, pt. 1. 25 26 National Fuel Gas Supply Corporation, 140 FERC ¶ 61,114 (2012). See e.g., Interstate Natural Gas Pipeline Rate Design, 47 FERC ¶ 61,295, at 62,052 n.14 (1989), describing the Commission’s “rate design process” as including four steps and stating that the last step, determining unit rates for each service, “is also known as rate design.” Docket Nos. CP15-115-000 and CP15-115-001 i. - 13 - Classifying the Cost of Service 38. As stated in its application, National Fuel’s first-year cost of service includes $1,012,064 in Operation & Maintenance (O&M) expenses. 27 Included in this figure are $151,302 in non-labor O&M expenses recorded in FERC account numbers 853 and 864. 28 Consistent with the Commission’s regulations requiring the use of straight fixedvariable rate design, these costs are classified as variable costs and should be recovered through a usage charge, not through the reservation charge as proposed. National Fuel states that these variable costs are de minimus—yielding an incremental commodity rate of only $0.0008 per Dth—and thus, nevertheless, proposes to recover them through the proposed reservation charge. We deny this proposal. 39. Section 284.7(e) of the Commission’s regulations does not allow the recovery of variable costs in the reservation charge. 29 There is no exception for de minimis costs. 30 Section 284.10(c)(2) states that variable costs should be used to determine the volumetric rate. 31 Misclassifying variable costs as fixed costs undermines the Commission's objectives in requiring straight fixed-variable rate design to facilitate transparent pricing and promote competition in the marketplace. Further, recovering variable costs (which the pipeline only incurs if shippers actually move gas over the pipeline) through the reservation charge (which firm shippers pay regardless whether they actually move gas over the pipeline) may result in the pipeline over-recovering its cost of service during 27 National Fuel March 17, 2015 Application, Ex. N, pt. 1 at 3. 28 National Fuel July 16, 2015 Response to Commission Staff’s July 7, 2015 Data Request, attach. at 1. The attached table separates the Operation and Maintenance (O&M) expenses by account and by labor versus non-labor costs. National Fuel identified $98,312 of variable costs in Account 853 (Compressor Station Labor & Expenses – Other) and $52,990 of variable costs in Account 864 (Maintenance – Compressor Station Equipment – Other) for a total of $151,302. 29 18 C.F.R. § 284.7(e) (2016). 30 Algonquin Gas Transmission, LLC, 150 FERC ¶ 61,163, at P 34 (2015); Algonquin Gas Transmission, LLC 151 FERC ¶ 61,118, at P 22 (2015). 31 18 C.F.R. § 284.10(c)(2) (2016). Docket Nos. CP15-115-000 and CP15-115-001 - 14 - times that shippers do not use 100 percent of their firm capacity and thus pay through the reservation charge for variable costs that the pipeline did not actually incur. 32 40. Therefore, consistent with prior Commission orders 33 and sections 284.7(e) and 284.10(c)(2) of the Commission’s regulations, we direct National Fuel to reclassify Account Nos. 853 and 864 non-labor costs as variable costs and to recalculate its incremental base reservation charge to omit the $151,302 in variable costs and recover only fixed costs when National Fuel files actual tariff records. 41. We approve, subject to the conditions below, National Fuel’s proposed incremental reservation charge for firm transportation services, as the initial recourse rates for service on the project. ii. Rate Design 42. National Fuel’s proposed incremental recourse rate for Rate Schedule FT/FT-S – NA2016 is based on a three-year levelized cost of service equal to $67,960,440. In response to a request from Commission staff, National Fuel explained its use of a levelized cost of service, including support for its methodology and the detailed calculations used to derive its reservation charge. 34 National Fuel explains that this method of levelization will under-recover the cost of service in the first year and overrecover the cost of service in later years. In the past the Commission has approved levelized cost-of-service rate designs, finding that they provided just and reasonable rates. 35 Given our previous approval of levelized annuity rate approaches and the lack of objections from other participants regarding the derivation of the rates, we will approve National Fuel’s proposed recourse rates subject to their recalculation as described in the preceding section. 32 See, e.g., Northwest Pipeline Corp., 71 FERC ¶ 61,253, at 61,997-99 (1995) (finding that Northwest's proposed non-conforming cost classification methodology was unsupported). 33 Columbia Gulf Transmission, LLC, 152 FERC ¶ 61,214, at P 21 (2015). 34 National Fuel September 21, 2015 Response to Commission Staff’s September 10, 2015 Data Request, response to question 1. 35 See, e.g., Cheniere Creole Trail Pipeline, L.P., 121 FERC ¶ 61,071, at PP 17-20 (2007); Dominion Cove Point, 115 FERC ¶ 61,337, at P 138 (2006). Docket Nos. CP15-115-000 and CP15-115-001 - 15 - 43. Under the Certificate Policy Statement, there is a presumption that the incremental rates should be charged for the proposed expansion capacity if the incremental rates would exceed the existing maximum system-wide rates. National Fuel’s proposes a monthly reservation charge of $11.3951 per Dth for Rate Schedule FT/FT-S – NA2016 service. National Fuel’s currently effective maximum monthly reservation charges for Rate Schedules FT/FT-S and FST services are $3.7805 per Dth and for Rate Schedule EFT service is $3.9653 per Dth. 36 While the Commission has not recalculated the reservation charge, it appears that National Fuel’s incremental recourse reservation rate will remain higher than National Fuel’s currently effective reservation charges even after National Fuel removes the improperly classified variable costs from the costs recoverable through the incremental reservation charge. 44. However, when National Fuel files an incremental commodity charge for Rate Schedule FT/FT-S – NA2016 service, which National Fuel informally calculated as $0.0008 per Dth per day, 37 this commodity charge will likely be lower than National Fuel’s currently effective maximum commodity charges of $0.0135 per Dth for Rate Schedules FT/FT-S and FST services and $0.0148 per Dth for Rate Schedule EFT service. 38 Therefore, we direct National Fuel to use its currently effective commodity charges for service using the project expansion capacity. 45. National Fuel did not propose a rate for interruptible service using the project expansion capacity. Therefore, National Fuel is directed to use its existing interruptible rate consistent with Commission policy requiring a pipeline to charge its currently effective system IT rates 39 for any interruptible service rendered on additional capacity 36 National Fuel’s currently effective maximum monthly reservation charges for Rate Schedules FT/FT-S and FST services are $3.7805 per Dth and for Rate Schedule EFT service is $3.9653 per Dth. National Fuel Gas Supply Corp., FERC NGA Gas Tariff, National Fuel Tariff, 4 - Applicable Rates, 4.010 – Transportation Rates, 12.0.0. 37 The informal calculation is based on total variable costs of $151,302 divided by 181,405,000 (the product of 497,000 Dth multiplied by 365 days). 38 National Fuel Gas Supply Corp., FERC NGA Gas Tariff, National Fuel Tariff, 4 - Applicable Rates, 4.010 – Transportation Rates, 12.0.0. 39 National Fuel’s currently effective Rate Schedule IT charge is $0.1378 per Dth. National Fuel Gas Supply Corporation FERC NGA Gas Tariff, 4 - Applicable Rates, 4.010 – Transportation Rates, 12.0.0. Docket Nos. CP15-115-000 and CP15-115-001 - 16 - made available as a result of an expansion that is integrated with existing pipeline facilities. 40 46. Consistent with the Certificate Policy Statement and with Order No. 710 as it applies to incremental facilities, 41 the Commission directs National Fuel to keep separate books and accounting of costs attributable to the project. National Fuel is required to file tariff records between 30 to 60 days prior to the date that the project facilities go into service reflecting the Rate Schedule FT/FT-S – NA2016 incremental rates. The books should be maintained with applicable cross-references, as required by section 154.309 of the Commission’s regulations. 42 This information must be sufficiently detailed so that the data can be identified in Statements G, I, and J in any future rate case under NGA section 4 or 5, and the information must be provided consistent with Order No. 710. 43 Such measures protect existing customers from cost overruns and from subsidization that might result from under-collection of the project’s incremental cost of service, as well as assist the Commission and parties to determine the costs of the project in later rate proceedings. iii. Fuel Retention 47. In its application, National Fuel stated that it intends to charge customers of the project the maximum fuel retention rates set forth in its existing FERC Gas Tariff. The currently-effective Transportation Fuel and Company Use Retention rate is 0.54 percent and the currently-effective Transportation Lost and Unaccounted For (LAUF) Retention rate is 0.42 percent. 44 Commission staff asked National Fuel to clarify what fuel rate it intends to charge customers of the project and further requested that National Fuel provide a fuel study with work papers demonstrating the impact that the Northern Access 40 See, e.g., Texas Eastern Transmission, LP, 139 FERC ¶ 61,138, at P 31 (2012); and Gulf South Pipeline Co., LP, 130 FERC ¶ 61,015, at P 23 (2010). 41 Revisions to Forms, Statements, and Reporting Requirements for Natural Gas Pipelines, Order No. 710, FERC Stats & Regs. ¶ 31,367, at P 23 (2008). 42 18 C.F.R. § 154.309 (2016). 43 See Order No. 710, FERC Stats ¶ Regs. ¶ 31,207. 44 August 18th Response, National Fuel Response 3. Docket Nos. CP15-115-000 and CP15-115-001 - 17 - 2016 Project will have on National Fuel’s current fuel rates to enable the Commission to make a fuel rate determination. 45 48. National Fuel restated that it intends to charge the current Transportation Fuel and Company Use Retention rate and the current LAUF Retention rate for a combined transportation fuel retention rate of 0.96 percent. 46 By contrast, National Fuel estimates that under a 100 percent load factor the proposed two new compressor engines at the Porterville Compressor Station, each rated at 2,675 HP, would consume incremental fuel equal to approximately 862 Dth per day. When divided by the project’s design capability of 497,000 Dth per day, this results in a maximum fuel usage of 0.17 percent. 49. When deciding whether to grant a pre-determination of a rolled-in fuel rate, the Commission compares the pipeline’s estimated incremental fuel rate to the pipeline’s existing system-wide fuel rate. If the estimated incremental fuel rate for the project is higher than the existing system-wide fuel rate, National Fuel would be required to charge the incremental fuel rate for project services and separately identify the incremental fuel associated with its project. Because the estimated maximum project fuel rate of 0.17 percent is substantially less than the system fuel rate of 0.54 percent, it is appropriate for National Fuel to charge the system fuel rate for its project. b. Tariff Provisions i. Limited Waiver Request 50. National Fuel requests a limited waiver of GT&C section 31.1 of its tariff so that National Fuel can accept a request from Seneca Resources to change the primary delivery point for a portion of its subscribed capacity two years after the proposed in-service date of the project. National Fuel and Seneca Resources entered into a precedent agreement for the full design capability of the project. Of the total 497,000 Dth per day, 140,000 Dth per day will have a primary delivery point at an interconnection with Tennessee’s 200 Line in Erie County, New York. Seneca Resources has requested that the delivery point be moved on November 1, 2018, to National Fuel’s existing interconnection with Transco’s pipeline system at Leidy in Potter County, Pennsylvania. 45 46 Commission Staff July 7, 2015 Data Request. National Fuel August 18, 2015 Response to Commission Staff’s July 7, 2015 Data Request, response to question 3. Docket Nos. CP15-115-000 and CP15-115-001 - 18 - 51. Under the Commission’s standard policy, a request for service cannot be submitted more than 90 days prior to the proposed commencement date of service unless some exception applies, for example if the construction of new facilities is required. National Fuel requests a limited waiver of General Terms & Conditions (GT&C) section 31.1 of its tariff, which incorporates the Commission’s prohibition: A “Service Request Form” shall be tendered no earlier than ninety days prior to the proposed commencement date of service, unless the construction of new facilities is required, unless the request is for capacity that will not be available until the proposed commencement date or unless the request is for capacity posted by Transporter pursuant to Section 26 of the General Terms and Conditions of this tariff.47 52. We will reject National Fuel’s request for a limited waiver of GT&C section 31.1. In previous orders the Commission has emphasized that the 90-day rule is “standard Commission policy” and that it provides the “appropriate time limit for commencement of service.” 48 The Commission intends that the 90-day rule prohibits shippers from unreasonably tying-up capacity. These concerns apply to existing shippers switching primary delivery points, despite the fact that these shippers are currently paying a reservation charge for their existing service. Commission policy does allow certain exceptions to the 90-day rule, such as for the construction of facilities that will result in a material increase in gas usage or production. The Commission has held that a special provision allowing shippers to change a primary point without following the regular procedures in the pipeline company’s tariff could adversely affect other shippers seeking primary point capacity from the pipeline. That is because the shipper with the special provision would have a priority not otherwise provided for in the generally applicable tariff for obtaining the primary capacity. Therefore, such a special right is contrary to Commission policy. 49 53. As National Fuel noted in its application, Seneca Resources’ requested delivery point change is irrespective of the Northern Access 2016 Project’s expansion capacity. Therefore, the exceptions to the 90-day rule, such as for the construction of facilities that 47 National Fuel Gas Supply Corporation FERC NGA Gas Tariff, 4 - Applicable Rates, 4.010 – Transportation Rates, 12.0.0. 48 49 Northern Natural Gas Co., 52 FERC ¶ 61,047, at 61,211-12 (1990). Columbia Gas Transmission, LLC, 153 FERC ¶ 61,098, at P 42 (2015), ANR Pipeline Co., 103 FERC ¶ 61,223 at PP 24-26 (2003), reh’g denied, 105 FERC ¶ 61,112 at P 22 (2003). Docket Nos. CP15-115-000 and CP15-115-001 - 19 - will result in a material increase in gas usage or production, do not apply. The requested waiver would give Seneca a special priority right to shift primary delivery point capacity outside the procedures of National Fuel’s generally applicable tariff for approximately two years beyond the issuance of this certificate for the project. While we have approved pipelines offering special contractual provisions in open seasons that are directly related to the new service to be provided by the expansion and do not adversely affect the rights of existing shippers, such as contract demand reduction or contract extension provision, the limited waiver requested here—which was not offered in the Open Season Notice— does not satisfy either criterion. 54. In addition, National Fuel has agreed to reserve capacity associated with the requested delivery point change until November 1, 2018. National Fuel states that it has reserved capacity in accordance with GT&C section 36 of its tariff. But GT&C section 36 explicitly limits the time period of such a reservation: If Transporter elects to reserve capacity for future expansion projects under this Section, such capacity may be reserved for up to one year prior to Transporter filing for certificate approval for the proposed expansion under Section 7(c) of the Natural Gas Act, and thereafter until such expansion is placed into service. 50 National Fuel has not shown that such reserved capacity for the proposed expansion project will be used when the expansion project is placed into service. To the contrary, National Fuel has indicated that the reserved capacity would be used beginning November 1, 2018, which will likely be more than one year after the in-service date of the project. National Fuel’s reservation of capacity conveys a special right to Seneca Resources and is contrary to National Fuel’s tariff. 55. At least 30 days, but not more than 60 days, before providing service to any project shipper under a non-conforming agreement, National Fuel must file an executed copy of the non-conforming agreement disclosing and reflecting all non-conforming language as part of National Fuel’s tariff and a tariff record identifying these agreements as non-conforming agreements consistent with section 154.112 of the Commission’s regulations. 51 50 National Fuel Gas Supply Corporation FERC NGA Gas Tariff, 4 - Applicable Rates, 4.010 – Transportation Rates, 12.0.0 (emphasis added). 51 18 C.F.R. § 154.112 (2016). Docket Nos. CP15-115-000 and CP15-115-001 ii. - 20 - Tariff Revisions 56. National Fuel proposes to add separate charts in section 4.010 its tariff to show each rate schedule that will apply to shippers using the capacity created by the project. These charts are designated “FT/FT-S – NA2016,” “EFT – NA2016,” and “FST – NA2016,” though the rates are identical. Additionally, National Fuel proposes to add language to section 3.1 of each Rate Schedule FT, FT-S, EFT, and FST 52 to clarify how the incremental rates will apply to National Fuel’s shippers. To the same purpose, National Fuel proposes to add two check boxes to Exhibit A of the Form of Service Agreement for each Rate Schedule 53 to indicate whether the service is or is not subject to the incremental rate. 57. We accept National Fuel’s revised pro forma tariff language. We direct National Fuel to file actual tariff records with its proposed revisions between 30 and 60 days prior to the date that the project facilities go into service. 2. Empire a. Initial Rates 58. Empire proposes to charge its existing system rates under Rate Schedule “FT – Original Empire Pipeline,” as the applicable recourse rates for the project. 54 The current year-round Rate Schedule FT – Original Empire Pipeline applies a reservation rate of $5.1827 per Dth per month and applies no commodity rate. 55 Empire’s first-year incremental cost of service is approximately $15,664,865. 56 Based on the maximum incremental daily firm transportation service quantity of 350,000 Dth, the Commission calculates an initial incremental reservation rate of approximately $3.7297 per Dth per 52 In the pro forma tariff these are designated “Schedule 6.010: FT Rate Schedule,” “Schedule 6.020: FT-S Rate Schedule,” “Schedule 6.030: EFT Rate Schedule,” and “Schedule 6.040: FST Rate Schedule.” 53 In the pro forma tariff these are designated “Form 8.010 – FT Form of Service Agreement,” “Form 8.020 – FT-S Form of Service Agreement,” “Form 8.030 – EFT Form of Service Agreement,” and “Form 8.040 – FST Form of Service Agreement.” 54 March 17, 2015 Application at 19. 55 Empire Pipeline, Inc. FERC NGA Gas Tariff, 4 – Applicable Rates, 4 – Applicable Rates, 8.0.0. 56 Amended Application, Revised Exhibit N, Part 2, Page 1 of 2. Docket Nos. CP15-115-000 and CP15-115-001 - 21 - month. Because the existing system rates exceed the incremental reservation rate, we find that Empire’s proposal to apply its Rate Schedule FT – Original Empire Pipeline rate as the maximum initial recourse rate for the project is reasonable. We accept this proposal. 59. Empire requests a pre-determination that the project costs qualify for rolled-in rate treatment into its existing Rate Schedule FT – Original Empire Pipeline rates in its next general section 4 rate case. As discussed below, the Commission will deny Empire’s request for a pre-determination based on its ten-year cost of service analysis provided in the application. 57 i. Pre-Determination of Rolled-In Rate Treatment 60. Empire and Seneca Resources have agreed to negotiated rates for the proposed services. Empire calculates annual revenue of $15.1 million under the negotiated rate. 58 Empire calculates that annual revenue will exceed later years’ costs of service, with total revenue over ten years exceeding total costs of service by approximately $16.1 million. However, Empire also calculates that operating expenses will exceed revenues for the project’s entire first year and for most of the second year before breaking even in the fourth quarter of the second year. 59 61. Were Empire to seek to increase its base tariff rates within the first couple of years after the project goes into service, then test period data may reflect that revenues for the project were not exceeding costs; thus, rolling in the project’s costs could result in FT customers subsidizing the project from the date that the new base rates become effective until Empire files a new rate proceeding. Because Empire could file its next rate case before project revenues exceed costs on an annual basis, the Commission believes it is premature to make a pre-determination on rolling in the proposed project’s costs 62. We do not preclude Empire from seeking to roll project costs into its FT system FT rates in its next section 4 rate case and demonstrating that the costs associated with the project can be rolled in without existing customers subsidizing the project. Empire 57 Amended Application, Empire Exhibit N, Part 2, Page 1of 2. 58 National Fuel November 11, 2015 Amendment to Joint Abbreviated Application, Ex. N, pt. 2 at 2. 59 The projected annual revenue shortfall for the first year is $503,705 and the projected annual revenue surplus for the second year is $47,291. National Fuel November 11, 2015 Amendment to Joint Abbreviated Application, Ex. N, pt. 2 at 1–2. Docket Nos. CP15-115-000 and CP15-115-001 - 22 - will bear the burden of proof to demonstrate that rolled-in rate treatment is just and reasonable. This holding is consistent with previous section 7 expansion projects in which the Commission denied a pre-determination of rolled-in rate treatment due to costs exceeding revenues in the first few years. 60 63. Consistent with the Certificate Policy Statement and consistent with Order No. 61 710 as it applies to incremental facilities, the Commission directs Empire to keep separate books and accounting of costs attributable to the project. Empire is required to file tariff records between 30 to 60 days prior to the date that the Project facilities go into service reflecting the appropriate Rate Schedule FT incremental rates. ii. Fuel Retention 64. Commission staff requested that Empire provide an analysis to support its proposed use of the 0.90 percent Pendleton Compressor Fuel Factor to also recover fuel and company use associated with the operation of the project compressors. 62 The Commission further requested that Empire provide a fuel study with work papers demonstrating the impact that the project will have on Empire’s current fuel consumption so that the Commission can make a determination about fuel retention rates. In its response, Empire states that it cannot predict or determine how the project will affect the fuel consumption along its system, given the dynamic nature of the nominations and the choices of its shippers for transportation and Empire’s lack of historical information on the planned use of the capacity that the Northern Access 2016 Project will create for Empire. Empire proposes to establish a separate fuel tracker for the Pendleton Compressor Station to determine the fuel percentage rate that Empire will charge shippers each month, at least until Empire obtains sufficient historical usage data. 63 Empire asserts that a comprehensive fuel study would be appropriate once operating 60 See Southern Natural Gas Co., 115 FERC ¶ 61,328, at P 39 (2006); Eastern Shore Natural Gas Co., 111 FERC ¶ 61,479, at P 22 (2005). 61 Order No. 710, FERC Stats. & Regs ¶ 31,207, at P 23. 62 Commission Staff July 7, 2015 Data Request. 63 Empire August 18, 2015 Response to July 7, 2015 Data Request, response 3(a). See, e.g., Millennium Pipeline Co. L.L.C., 117 FERC ¶ 61,319, at P 196 (2006) (granting Empire’s request for clarification that compressor fuel at the Oakfield Compressor Station will be recovered via a compressor fuel factor posted on its website on a monthly basis). Docket Nos. CP15-115-000 and CP15-115-001 - 23 - history is better known, suggesting a fuel study should not be required sooner than 18 months from the in-service date of project. 64 65. The Commission will approve the 0.90 percent initial Pendleton Compressor Fuel factor. Empire’s fuel tracker true-up relieves both the pipeline and the shippers from the risks of over- and under-recoveries by ensuring that all parties are kept whole. The Commission will require Empire to file between 60 and 30 days before the in-service date, the initial fuel factor of 0.90 percent associated with the fuel requirements resulting from the project. The Commission will also require Empire to track initial fuel use associated with the project pursuant to GT&C section 23. b. Tariff Provisions 66. Empire proposes to revise the definition of “Compressor Fuel” in GT&C section 1.9 of its tariff to include the new Pendleton, New York, compressor station. Empire also proposes to revise the definition of “Original Empire Pipeline” in GT&C section 1.36 of its tariff to include Line EMP-03 and new facilities in Niagara County, New York. Further, Empire proposes to revise GT&C sections 23.2 to 23.6 to define those shippers subject to Empire’s proposed Pendleton Compressor Fuel factor and to separately identify the two compressor stations, Oakfield and Pendleton. Lastly, Empire proposes to modify sections 2.3(a) and 2.3(b) of its Rate Schedule FT to refer to the revised GT&C section 23. 67. We accept Empire's revised pro forma tariff language. We direct Empire to file actual tariff records with its proposed revisions between 30 and 60 days prior to the date that the project facilities go into service. D. Environmental Analysis 68. On July 24, 2014, the Commission staff began its environmental review of the Northern Access 2016 Project by granting National Fuel’s and Empire’s request to use the pre-filing process. See Docket No. PF14-18-000. As part of the pre-filing review, staff participated in open house informational meetings sponsored by National Fuel and Empire in the towns of Olean, Sardinia, and North Tonawanda, New York, on August 26, 27, and 28, 2014, to explain the Commission’s environmental review process to interested stakeholders. 69. On October 22, 2014, the Commission issued a Notice of Intent to Prepare an Environmental Assessment for the Planned Northern Access 2016 Project, Request for 64 Empire August 18, 2015 Response to July 7, 2015 Data Request, response 3(a). Docket Nos. CP15-115-000 and CP15-115-001 - 24 - Comments on Environmental Issues, and Notice of Public Scoping Meetings (NOI). 65 The NOI was mailed to interested parties including federal, state, and local officials; agency representatives; environmental and public interest groups; Native American tribes; local libraries and newspapers; and affected property owners. On November 3 and 5, 2014, the Commission held scoping meetings in the towns of St. Bonaventure and Springville, New York. In total, two people provided verbal comments at the meetings. Transcripts were entered into the public record in Docket No. PF14-18-000. 70. Commission staff’s pre-filing review ended on March 17, 2015, when National Fuel and Empire filed the project application. On April 29, 2015, the Commission issued a Supplemental Notice of Intent to Prepare an Environmental Assessment for the Proposed Northern Access 2016 Project, Request for Comments on Environmental Issues, Notice of Environmental Site Review, and Notice of Public Scoping Meeting (supplemental NOI) to seek comments on the locations proposed by National Fuel for one new compressor station and one natural gas dehydration facility in Niagara County, New York. 66 On May 20, 2015, the Commission held an additional scoping meeting in the town of North Tonawanda, New York. Forty people provided verbal comments. The transcript was entered into the public record in Docket No. CP15-115-000. 71. Based on public input received throughout the scoping process, National Fuel filed an amendment to its application on November 2, 2015, to propose a new location for its Pendleton Compressor Station and to make other modifications to its proposed facilities. On November 22, 2015, the Commission issued another Supplemental Notice of Intent to Prepare an Environmental Assessment for the Proposed Northern Access 2016 Project and Request for Comments on Environmental Issues to solicit input on the revised location of the new (Pendleton) Compressor Station. 67 In total, Commission staff received 170 separate written comments in response to the second supplemental NOI. Comments were entered into the public record for National Fuel’s amended application in Docket No. CP15-115-001. 72. To satisfy the requirements of the National Environmental Policy Act of 1969 (NEPA), our staff prepared an environmental assessment (EA) for National Fuel’s proposal. The analysis in the EA addresses geology, soils, water resources, wetlands, vegetation, fisheries, wildlife, threatened and endangered species, land use, recreation, visual resources, cultural resources, socioeconomics, air quality, noise, safety, cumulative 65 79 Fed. Reg. 64,379 (Oct. 29, 2014). 66 80 Fed. Reg. 26,015 (May 6, 2015). 67 80 Fed. Reg. 75,088 (Dec. 1, 2015). Docket Nos. CP15-115-000 and CP15-115-001 - 25 - impacts, and alternatives. All substantive comments received in response to the NOIs were addressed in the EA. 68 73. The EA reflects modifications that National Fuel incorporated into its project design during the pre-filing process. A number of the adopted design modifications and alternatives address stakeholder concerns and/or avoid or minimize environmental impacts. National Fuel adopted these modifications and made them part of the project when National Fuel filed its original and amended applications. 74. Specifically, National Fuel considered 36 route variations along the originally considered pipeline route during pre-filing, based on landowner and agency input as well as resources identified during the preliminary route design. Many of these route variations, each less than 4 miles long, were incorporated into the proposed route to address specific environmental, landowner, or construction issues without unnecessarily encumbering additional landowners. National Fuel also modified the locations and methods of several waterbody crossings to accommodate comments and concerns raised by federal and state agencies. 75. Additionally, the EA evaluated several alternative compressor station sites due to numerous stakeholder comments. Many of the alternative sites were eliminated due to environmental or land use constraints. Further, due to many stakeholder objections to the originally-proposed compressor station site along Aiken Road (Alternative Site #1 in the EA) and a landowner’s unwillingness to sell the property, National Fuel proposed a new site for the Pendleton Compressor Station (i.e., the location on Killian Road, which is analyzed as the proposed action in the EA). This change in the proposed location of the compressor station site was the most significant change to the project proposal from the original pre-filing project. 76. The EA was issued on July 27, 2016, opening a 30-day comment period. 69 In response to the EA, National Fuel filed several clarifications and project design changes. These are discussed below. We also received comments on the EA from the U.S. Environmental Protection Agency (EPA), the U.S. Fish and Wildlife Service (FWS), the New York State Department of Environmental Conservation (NYSDEC), the Town of Pendleton, several non-governmental organizations, and many individuals, including several who submitted multiple comments. Several commenters requested that the Commission extend the public comment period. The commenters raised the following 68 The EA provides a summary of commenters and comments received during the scoping period. EA at 3 tbl.A.3-1, 4. 69 81 Fed Reg. 51,873 (Aug. 5, 2016). Docket Nos. CP15-115-000 and CP15-115-001 - 26 - concerns: the need to develop a programmatic NEPA review of the Commission’s NGA jurisdiction over proposed projects; the need to develop an Environmental Impact Statement for the Northern Access 2016 Project; the purpose and need for the project; the EA’s considered alternatives; the direct impact of the project on water resources and wetlands, biological resources, socioeconomics and visual resources, noise, air quality, historic and archaeological resources, and greenhouse gases; indirect impacts from induced natural gas development; and cumulative impacts. 1. Clarifications and corrections 77. On August 24, 2016, National Fuel submitted several clarifications or modifications of the proposed project in response to the EA. Unless noted below, these clarifications and modifications have been reviewed, found to be consistent with the discussion of potential impacts presented in the EA, and do not change the EA’s conclusion that the project is not expected to have significant impacts on environmental resources. 78. National Fuel noted that the proposed tie-in and metering and regulation station at the Hinsdale Compressor Station, which was constructed as part of the Northern Access 2015 Project, will be located within the laydown area used during construction of the station. National Fuel recommended that the Commission make a conforming revision to environmental recommendation 14 of the EA, which would require that National Fuel file a geotechnical exploration report that evaluates slope configurations and stability for the Hinsdale and Pendleton Compressor Stations, meter and regulator station, and interconnect with Tennessee. We have reviewed this request and agree with the revision. Environmental Condition 14, included in Appendix B of this order, incorporates this clarification. 79. National Fuel contends that it is not likely that karst topography will be encountered during construction. National Fuel requests removal of environmental recommendation 15 of the EA, which would require that National Fuel file a desktop evaluation of karst development in all work areas, a geotechnical investigation of karst development at the Pendleton Compressor Station and two other sites (plus additional sites if necessary); and a karst mitigation plan. We disagree. As stated in the EA, several project facilities sit in areas that have the potential for karst features. These include the EMP-03 Pipeline, Wheatfield Dehydration Facility, and Pendleton Compressor Station. 70 However, Environmental Condition 15, included in Appendix B of this order, eliminates the Pendleton Compressor Station site from a karst evaluation because the borings completed for that site do not imply karst conditions. EPA states that the information in 70 EA at 25. Docket Nos. CP15-115-000 and CP15-115-001 - 27 - the future karst mitigation plan should have been included in the EA for public review and comment. We disagree. Both the EA’s description of karst terrain as a geologic hazard and the EA’s description of the construction-related mitigation measures that must be included in the karst mitigation plan put interested parties on notice of the types of activities contemplated, their potential impacts, and likely mitigation measures. 71 In addition, this order responds to substantive comments filed in response to the EA. Also, the karst mitigation plan, like any information filed after the issuance of the EA, will be accessible to the public in the Commission's electronic database, eLibrary. 72 80. National Fuel now proposes to cross Buffalo Creek using the horizontal directional drill method rather than the wet open-cut method discussed in the EA. 73 This change in crossing method would result in a reduction of environmental impacts at this location. 74 National Fuel also clarified that one proposed contractor yard is no longer needed and that several additional yards do not appear on maps included with the EA. We incorporate these clarifications by reference. We have reviewed the sites and conclude that impacts from these areas will not be significant. 81. One commenter notes that the EA incorrectly referenced section 306(b) of the Commission’s regulations to determine whether an EA or EIS is necessary. 75 The proper citation is to section 380.6. 76 Additionally, several commenters noted that the EA’s alternatives discussion inconsistently stated that the objective of the Northern Access 2016 Project is “to provide transportation of 847,000 Dth per day of natural gas capacity . . . .” 77 The correct description of the objective is to provide 497,000 Dth per day of incremental firm transportation service. 71 EA at 25, 28-29. 72 The eLibrary system offers interested parties the option of receiving automatic notification of new filings. 73 EA at 42. 74 EA at 42-45. 75 EA at 4 (citing 18 C.F.R. § 306(b) (2016)). 76 18 C.F.R. § 380.6 (2016) (identifying actions that require an EIS). 77 EA at 161. Docket Nos. CP15-115-000 and CP15-115-001 2. - 28 - The need for a programmatic environmental review 82. Council on Environmental Quality (CEQ) regulations do not require broad or “programmatic” NEPA reviews. CEQ has stated, however, that such a review may be appropriate where an agency: (1) is adopting official policy; (2) is adopting a formal plan; (3) is adopting an agency program; or (4) is proceeding with multiple projects that are temporally and spatially connected. 78 The Supreme Court has held that a NEPA review covering an entire region (that is, a programmatic review) is required only “if there has been a report or recommendation on a proposal for major federal action” with respect to this region. 79 Moreover, there is no requirement for a programmatic EIS where the agency cannot identify the projects that may be sited within a region because individual permit applications will be filed at a later time. 80 83. We have explained that there is no Commission plan, policy, or program for the development of natural gas infrastructure. 81 Rather, the Commission acts on individual applications filed by entities proposing to construct interstate natural gas pipelines. Under NGA section 7, the Commission is obligated to authorize a project if it finds that the construction and operation of the proposed facilities “is or will be required by the present or future public convenience and necessity.” 82 What is required by NEPA, and what the Commission provides, is a thorough examination of the potential impacts of specific projects. As to projects that have a clear physical, functional, and temporal nexus such that they are connected or cumulative actions, 83 the Commission will prepare a multiple-project environmental document. 84 78 See Memorandum from CEQ to Heads of Federal Departments and Agencies, Effective Use of Programmatic NEPA Reviews at 13-15 (Dec. 18, 2014) (citing 40 C.F.R. § 1508.18(b)) (CEQ 2014 Programmatic Guidance). 79 Kleppe v. Sierra Club, 427 U.S. 390 (1976) (holding that a broad-based environmental document is not required regarding decisions by federal agencies to allow future private activity within a region). 80 See Piedmont Envtl. Council v. FERC, 558 F.3d 304, 316-317 (4th Cir. 2009) (Piedmont). 81 See, e.g., National Fuel Gas Supply Corp., 154 FERC ¶ 61,180, at P 13 (2016); Texas Eastern Transmission, LP, 149 FERC ¶ 61,259, at PP 38-47 (2014). 82 15 U.S.C. § 717f(e) (2012). 83 40 C.F.R. § 1508.25(a)(1)-(2) (2016) (defining connected and cumulative (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 29 - 84. The organizations Allegheny Defense Project, Appalachian Mountain Advocates, Heartwood, and Pennsylvania Alliance for Clean Water and Air (Conservation Groups) contend that the Commission violated NEPA by failing to prepare a programmatic EIS for natural gas infrastructure projects related to natural gas development in the Appalachian Basin region. 85 The groups point to a number of gas infrastructure projects in various stages of planning in the Appalachian Basin, claiming that they will collectively “have cumulative or synergistic environmental impacts upon a region.” 86 Further, the groups claim that even if future pipeline projects may be theoretical, this does not mean that the Commission would not be able to “establish parameters for subsequent analysis.” 87 The Conservation Groups claim that a programmatic EIS may aid the Commission’s and the public’s understanding of broadly foreseeable consequences of NGA-jurisdictional projects and non-jurisdictional shale gas production in the Appalachian Basin. 85. The Conservation Groups also argue that CEQ’s 2014 Programmatic Guidance recommends a programmatic EIS when “several energy development programs proposed in the same region of the country . . . [have] similar proposed methods of implementation and similar best practice and mitigation measures that can be analyzed in the same document.” 88 In support, the Conservation Groups point to a Programmatic EIS developed by the DOE and U.S. Bureau of Land Management to consider the environmental impacts of solar energy development in six southwestern states. 89 The Conservation Groups urge the Commission to adopt a similar approach for natural gas development in the Appalachian Basin. actions). 84 See, e.g., EA for the Monroe to Cornwell Project and the Utica Access Project, Docket Nos. CP15-7-000 & CP15-87-000 (filed Aug. 19, 2015); Final Multi-Project Environmental Impact Statement for Hydropower Licenses: Susquehanna River Hydroelectric Projects, Project Nos. 1888-030, 2355-018, and 405-106 (filed Mar. 11, 2015). 85 Conservation Groups August 29, 2016 Comments on the EA at 57-5. 86 Id. at 58-59 (citing Kleppe, 427 U.S. at 409-410). 87 Id. at 59 (citing CEQ 2014 Programmatic Guidance at 11). 88 Id. (citing CEQ 2014 Programmatic Guidance at 11). 89 Id. at 61. Docket Nos. CP15-115-000 and CP15-115-001 - 30 - 86. The fact that a number of individual pipeline companies have planned or proposed infrastructure projects to increase capacity to transport natural gas throughout the Appalachian Basin and elsewhere in the country does not establish that the Commission is engaged in regional development or planning. 90 Rather, this information confirms that pipeline projects to transport natural gas are initiated solely by private industry. As we have noted previously, a programmatic EIS is not required to evaluate the regional development of a resource by private industry if the development is not part of, or responsive to, a federal plan or program in that region. 91 87. The Commission’s siting decisions regarding pending and future natural gas pipeline facilities are only in response to proposals by private industry, and the Commission has no way to accurately predict the scale, timing, and location of projects, much less the type of facilities that will be proposed. 92 In these circumstances, the Commission’s longstanding practice to conduct an environmental review for each proposed project, or a number of proposed projects that are interdependent or otherwise interrelated or connected, “should facilitate, not impede, adequate environmental assessment.” 93 Thus, here the Commission’s environmental review of National Fuel’s and Empire’s actual proposed project in a discrete EA is appropriate under NEPA. 88. In sum, CEQ states that a programmatic EIS can “add value and efficiency to the decision-making process when they inform the scope of decisions,” “facilitate decisions on agency actions that precede site- or project-specific decisions and actions,” or 90 See, e.g., Sierra Club v. FERC, 827 F.3d 36, 50 (D.C. Cir. 2016) (Freeport LNG) (rejecting claim that NEPA requires FERC to undertake a nationwide analysis of all applications for liquefied natural gas export facilities); cf. Myersville Citizens for a Rural Cmty., Inc. v. FERC, 783 F.3d 1301, 1326-27 (D.C. Cir. 2015) (Myersville) (upholding FERC determination that, although a Dominion Transmission Inc.-owned pipeline project’s excess capacity may be used to move gas to the Cove Point terminal for export, the projects are “unrelated” for purposes of NEPA). 91 See, e.g., Kleppe, 427 U.S. at 401-02. 92 Lack of jurisdiction over an action does not necessarily preclude an agency from considering the potential impacts. However, as explained in the cumulative impacts section of this order, it reinforces our finding that because states, and not the Commission, have jurisdiction over natural gas production and associated development (including siting and permitting), the location, scale, timing, and potential impacts from such development are even more speculative. 93 Id. Docket Nos. CP15-115-000 and CP15-115-001 - 31 - “provide information and analyses that can be incorporated by reference in future NEPA reviews.” 94 The Commission does not believe these benefits can be realized by a programmatic review of natural gas infrastructure projects because the projects subject to our jurisdiction do not share sufficient elements in common to narrow future alternatives or expedite the current detailed assessment of each particular project. Thus, we find a programmatic EIS is neither required nor useful under the circumstances here. 3. The Commission’s choice to compose an Environmental Assessment 89. The Conservation Groups argue that the Commission’s EA, at 199 pages, exceeds both the length recommended by the Council on Environmental Quality (CEQ) and the length logically necessary to determine whether the project’s environmental impacts would be significant. 95 The groups assert that the EA’s length proves that an Environmental Impact Statement (EIS) is necessary to analyze the project’s potential impacts. 90. The CEQ’s advisory memorandum is general guidance to agencies and is not binding. While the advisory memorandum urges brevity in the preparation of an EA, it does not require an agency to prepare an EIS if it issues an EA larger than the CEQ’s recommended 15 pages. The CEQ’s guidance recognizes that a lengthy EA may be appropriate in cases of complexity, and while a lengthy EA sometimes may suggest the need for an EIS, the CEQ’s guidance does not establish a blanket requirement. Here, the 199-page length of the EA was the product of a broad range of environmental issues in the resource reports, each of which was capable of being addressed through required mitigation to reduce the project's effects below the level of significance to warrant an EIS. The mere volume of these otherwise relatively non-complex environmental issues does not warrant further analysis in an EIS. The EA adequately addresses the numerous issues as concisely and briefly as possible, as Commission and CEQ regulations require. The EA also describes measures to mitigate anticipated environmental impacts—enabling public review and comment—and recommends that many such measures be incorporated as conditions if the Commission issues a certificate for the project. 96 And in any case, 94 CEQ 2014 Programmatic Guidance at 13. 95 Conservation Groups August 29, 2016 Comments on the EA at 8-9. (citing Forty Most Asked Questions Concerning CEQ’s National Environmental Policy Act Regulations, 46 Fed. Reg. 18,026 (Mar. 23, 1981)). 96 Nat’l Parks Ass’n v. Babbitt, 241 F.3d 722, 735 (9th Cir. 2001) (citing Wetlands Action Network v. U.S. Army Corps of Eng’rs, 222 F.3d 1105, 1121 (9th Cir. 2000) (mitigation measures deemed sufficient to justify an agency’s decision to forego issuing (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 32 - courts have held that the length of an EA “has no bearing on the necessity of an EIS.” 97 “What ultimately determines whether an EIS rather than an EA is required is the scope of the project itself, not the length of the agency’s report.” 98 A rule requiring an EIS for any EA over a certain number of pages would create a perverse incentive for agencies to produce bare-bones EAs. 99 91. Furthermore, as the EA explains, the Commission’s regulations implementing NEPA provide that “[i]f the Commission believes that a proposed action . . . may not be a major federal action significantly affecting the quality of the human environment, an EA, rather than an EIS, will be prepared first. Depending on the outcome of the EA, an EIS may or may not be prepared.” 100 National Fuel proposes to construct a new pipeline with 69 percent of its length located along existing pipeline or utility rights-of-way, 101 as well as one new and one modified gas-fired compressor station and one new dehydration facility, with related smaller facilities. The Commission’s decades of experience implementing NEPA for pipeline projects indicates that such a project normally would not fall under the “major” category for which an EIS is automatically prepared. 102 This an EIS)); Friends of the Ompompanoosuc v. FERC, 968 F.2d 1549, 1555 (2d Cir. 1992) (the Commission’s consideration of mitigation measures is a rational basis for a finding of no significant impact). 97 Tomac v. Norton, 433 F.3d 852, 862 (D.C. Cir. 2005) (citing Sierra Club v. Marsh, 769 F.2d 868, 875 (1st Cir. 1985)). 98 Id. (quoting Heartwood, Inc. v. U.S. Forest Serv., 380 F.3d 428, 434 (8th Cir. 2004)). 99 Heartwood, Inc. v. U.S. Forest Serv., 380 F.3d 428, 434 (8th Cir. 2004). 100 EA at 4 (quoting 18 C.F.R. § 380.6(b) (2016)). 101 EA at 7 tbl.A.4a-1. 102 See 18 C.F.R. § 380.6(b) (2016) (giving the Commission discretion to prepare an EA in lieu of an EIS if the Commission believes that a proposed action may not be a major action significantly affecting the quality of the human environment); see also 18 C.F.R. § 380.6(a)(3) (2016) (with respect to pipeline projects, actions that require an EIS are major pipeline construction projects using rights-of-way in which there is no existing natural gas pipeline); see, e.g., Tenn. Gas Pipeline Co., 131 FERC ¶ 61,140 (2010) (EA issued for a project consisting of 127.4 miles of 30-inch-diameter pipeline loops in Pennsylvania and New Jersey); Magnum Gas Storage, LLC, 134 FERC ¶ 61,197 (2011) (EA issued for a project which included a gas storage field on 2,050-acre site and (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 33 - category emphasizes construction and operation of projects of greater scope and complexity than the one proposed here. As explained below, based on the EA’s analysis and staff’s recommended mitigation measures, the EA concludes, and we agree, that approval of the Northern Access 2016 Project would not constitute a major federal action significantly affecting the quality of the human environment. 103 Thus, an EIS is not required. 104 4. Purpose and Need 92. An agency’s environmental document must include a brief statement of the purpose and need to which the proposed action is responding. 105 An agency uses the purpose and need statement to define the objectives of a proposed action and then to identify and consider legitimate alternatives. 106 The Council on Environmental Quality has explained that “[r]easonable alternatives include those that are practical or feasible from the technical and economic standpoint and using common sense, rather than simply desirable from the standpoint of the applicant.” 107 associated 61.6-mile, 36-inch-diameter pipeline in Utah); Colo. Interstate Gas Co., 131 FERC ¶ 61,086 (2010) (EA issued for a project which included two new 16-inchdiameter pipeline laterals totaling 118 miles in length in Colorado); Equitrans, L.P., 117 FERC ¶ 61,184 (2006) (EA issued for a project which included 68 miles of new 20-inch-diameter pipeline in Kentucky). 103 EA at 177. Under section 1508.18 of CEQ’s regulations, “a ‘major federal action’ includes actions with effects that may be major and which are potentially subject to Federal control and responsibility. Major reinforces but does not have a meaning independent of significantly.” 40 C.F.R. § 1508.18 (2016) “Significantly” requires consideration of both the context and intensity of the project. Id. § 1508.27. 104 CEQ regulations state that, where an EA results in a finding of no significant impact, an agency may proceed without preparing an EIS. 40 C.F.R. §§ 1501.4(e), 1508.13 (2016). 105 See 40 C.F.R. § 1508.9 (2016) (for an Environmental Assessment); id. § 1502.13 (for an Environmental Impact Statement). 106 107 See Colo. Envtl. Coal. v. Dombeck, 185 F.3d 1162, 1175 (10th Cir. 1999). Forty Most Asked Questions Concerning CEQ’s National Environmental Policy Act Regulations, 46 Fed. Reg. 18,026, 18,027 (Mar. 23, 1981). Docket Nos. CP15-115-000 and CP15-115-001 - 34 - 93. The EA for the Northern Access 2016 Project accepts National Fuel and Empire’s articulation of the purpose and need to provide 350,000 Dth per day of “incremental firm transportation service to markets in the northeastern United States and Canada . . . as well as markets on the Tennessee Gas 200 Line in Erie County, New York, and other interconnections with local gas distribution companies, power generators, and other interstate pipelines available on both the National Fuel and Empire systems.” 108 The EA also notes that “market demand” is one of several factors upon which the Commission makes a separate conclusion under section 7 of the NGA, to be articulated in the later order to issue or deny a certificate, of whether a proposed project “is or will be required by the present or future public convenience and necessity.” 109 This standard includes economic need and other factors bearing on the public interest. 110 94. Several commenters dispute the statements in National Fuel’s application about the market need for the project, and they object to the EA’s acceptance of National Fuel’s statements as the “purpose and need” for NEPA analysis. They also perceive the EA’s cross-reference to the later NGA section 7 analysis as an improper deferral of an independent “purpose and need” analysis. They argue that this deferral denies the public’s right under NEPA to comment on all aspects of the EA, including the statement of “purpose and need” and the resulting alternatives analysis. 95. The EA’s statement of purpose and need satisfied NEPA. An agency’s definition of purpose and need, its choice of alternatives, and the depth of discussion of those alternatives must be reasonable. 111 Courts have upheld federal agencies use of applicants’ identified project purpose and need as the basis for evaluating alternatives. 112 Where an agency is asked to sanction a specific plan, the agency should take into account the needs and goals of the parties involved in the application. 113 We acknowledge that a project’s purpose and need may not be so narrowly defined as to preclude consideration 108 EA at 2. 109 EA at 2; 15 U.S.C. § 717f(e) (2012). 110 Atlantic Refining Co. v. Pub. Serv. Comm’n of NY, 360 U.S. 378, 391 (1959). 111 Citizens Against Burlington, Inc. v. Busey, 938 F.2d 190, 196 (D.C. Cir. 1991). 112 E.g., City of Grapevine v. U.S. Dep’t of Transp., 17 F.3d 1502, 1506 (D.C. Cir. 1994). 113 Busey, 938 F.2d at 199. Docket Nos. CP15-115-000 and CP15-115-001 - 35 - of what may actually be reasonable choices. 114 But an agency need only consider alternatives that will bring about the ends of the proposed action, and the evaluation is shaped by the application at issue and by the function that the agency plays in the decisional process. 115 96. Here the EA’s reliance on National Fuel’s and Empire’s statements about purpose and need was reasonable given the content of their application and the Commission’s position in the decisional process. The commenters argue, in effect, that the Commission should analyze broad economic need, for example across the entire Northeast region, and should effectively plan the way that alternative natural gas projects, other energy sources, or energy conservation could satisfy that broad economic need. Though the NGA’s public convenience and necessity standard is broad, the Commission’s powers under section 7 are limited. The Commission can issue a certificate for a proposed project subject to “such reasonable terms and conditions as the public convenience and necessity may require,” but the Commission cannot order, for example, that a natural gas company carry gas from or to Commission-favored producers or users. Similarly, the Commission can exercise a veto power over the proposed project if, and only if, a balance of all the circumstances weighs against certification. 116 5. Alternatives Analysis 97. Based on the statement of purpose and need, the EA evaluated a no-action alternative, system alternatives using two existing pipeline systems in the project area, two major route alternatives, 36 potential variations to National Fuel’s original proposed route, and alternative sites for the aboveground facilities. 98. Commenters contend that the EA’s alternatives analysis is inadequate. Commenters allege that the EA incorrectly dismisses the no-action alternative and alternative locations for the new Pendleton Compressor Station and Wheatfield Dehydration Facility, fails to analyze alternative dehydration technologies at the Wheatfield Dehydration Facility, and fails to assess renewable energy alternatives or increased energy efficiency. 114 Alaska Survival v. Surface Transp. Bd., 705 F.3d 1073, 1085 (9th Cir. 2012); Simmons v. U.S. Army Corps. of Eng’rs, 120 F.3d 664, 669 (7th Cir. 1997); Busey, 938 F.2d at 198-99. 115 116 Busey, 938 F.2d at 1991. E.g., Fed. Power Comm’n v. Transcont’l Gas Pipe Line Corp., 365 U.S. at 17; Jordan Cove Energy Project, L.P., 154 FERC ¶ 61,190, at PP 28-42 (2016). Docket Nos. CP15-115-000 and CP15-115-001 - 36 - 99. As stated above, an agency’s definition of purpose and need, its choice of alternatives, and the depth of discussion of those alternatives must be reasonable. 117 NEPA does not define what constitute “reasonable alternatives”; however, CEQ guidance provides that “a reasonable range of alternatives depends on the nature of the proposal and the facts in each case.” 118 An agency need only consider alternatives that will bring about the ends of the proposed action, and the evaluation is shaped by the application at issue and by the function that the agency plays in the decisional process. 119 Alternatives that are remote, conjectural, or do not meet the purpose or need of the proposed action may be eliminated so long as the agency briefly discusses the reasons for the elimination. 120 An agency’s specification of the range of reasonable alternatives is entitled to deference. 121 100. The EA adequately discusses the reasons for eliminating each alternative from further consideration. The EA acknowledges that under a no-action alternative the environmental impacts identified in the EA would not occur, 122 but it explains that the no-action alternative would not satisfy the purpose and need for the proposed project to deliver natural gas to markets in the northeastern United States and Canada and would result in customers in these regions seeking to construct alternative transportation facilities that may cause similar or greater environmental impacts than the Northern Access 2016 Project without achieving the purpose and need within the same timeframe as the Northern Access 2016 Project. For these reasons, the EA did not recommend the no-action alternative. This discussion satisfied NEPA; we affirm the EA’s conclusion. 101. Commission staff evaluated several preliminary sites for the new Pendleton Compressor Station that National Fuel identified in its environmental resource reports. As noted in the EA, many of these sites were eliminated because they were more severely constrained for space or had considerable additional resource impacts, including 117 E.g., Busey, 938 F.2d at 196. 118 Forty Most Asked Questions Concerning CEQ’s National Environmental Policy Act Regulations, 46 Fed. Reg. 18,026, 18,027 (1981). 119 Busey, 938 F.2d at 195, 199. 120 40 C.F.R. § 1502.14(a) (2016). 121 Busey, 938 F.2d at 196. 122 EA at 162. Docket Nos. CP15-115-000 and CP15-115-001 - 37 - proximity to residences, wetland impacts, and forest-clearing. 123 National Fuel’s most significant change from the original pre-filing proposal was to propose a new site along Killian Road for the new Pendleton Compressor Station. The EA eliminates the originally proposed site along Aiken Road (Alternative Site #1) because it would require the replacement of 3.05 miles of pipeline adjacent to a hazardous waste site, would sit closer than any other alternative site to nearby noise-sensitive areas, has 80 parcels with houses within 0.5 mile, is zoned residential, would affect more wetlands than the preferred Killian Road site, and would require the use of eminent domain to take the property rights. 124 This discussion satisfied NEPA. 125 102. Numerous commenters question why the EA rejects the site in the Town of Cambria, in Niagara County (Alternative Site #2). They suggest that the Cambria Site’s proximity to an existing compressor station and its distance from existing homes make the Cambria Site preferable. However, as stated in the EA, the additional 5.5 miles of new pipeline right-of-way required to reach that site would disturb an additional 78.2 acres including wetlands and would cross more than 50 additional parcels. 126 Further, as noted in the EA, the nearby existing compressor station and related pipeline, among other existing infrastructure, would act as an engineering barrier to much of the Cambria Site. 127 For these reasons, EA concludes that the Cambria Site offers no environmental benefit over the proposed Killian Road site. This discussion satisfied NEPA. 128 123 EA at 167. 124 EA at 172. 125 See Minisink Residents for Envtl. Pres. and Safety v. FERC, 762 F.3d 97, 102 (D.C. Cir. 2014) (quoting Midcoast Interstate Transmission, Inc. v. FERC, 198 F.3d 960, 967 (D.C. Cir. 2000)). The Commission’s NEPA obligation requires that it identify the reasonably alternatives to the contemplated action and look hard at the environmental effects of its decision. 126 EA at 172-173. 127 Id. 128 See Midcoast Interstate Transmission, 198 F.3d at 967-68 (the Commission must carefully consider alternatives, but even in the face of a preferable alternative, the Commission may reasonably find that the proposed project is required by the public convenience and necessity). Docket Nos. CP15-115-000 and CP15-115-001 - 38 - 103. A third alternative site was examined as a location for both the new Pendleton Compressor Station and the Wheatfield Dehydration Facility. The EA eliminated this site as an alternative for the new Pendleton Compressor Station because it would require 3.3 miles of additional pipeline that would cross 17 acres of wetlands and require some permanent wetland fill, would have 390 parcels with houses within 0.5 mile (many more than other alternatives), and would raise special concerns about safety, noise, and construction given that the area around the site is heavily populated. 129 But the EA recommends the site as the location for the Wheatfield Dehydration Facility because this facility will not require new pipeline construction, this facility’s smaller footprint will not affect wetlands, no air quality or noise impacts are expected from the facility, and because the site’s proximity to the existing Oakfield Compressor Station (not part of this project) and the new Pendleton Compressor Station would improve the performance of the dehydration facilities. By contrast, the EA eliminates the originally-proposed site for the Wheatfield Dehydration Facility because its proximity to the Niagara Falls Air Reserve Station raised safety concerns, eliminates a site on Grand Island, New York, because its position farther from the compressor stations impairs the performance of the dehydration facilities, and eliminates a site in Canada because the Commission must place facilities necessary for the operation of a certificated project within United States territory. The EA’s discussion satisfied NEPA. 104. The EA also briefly discusses its reasons for eliminating two alternative dehydration technologies suggested by commenters. The EA explains that “methanol injection” is not a dehydration process and that “dessicant dehydration systems” are not feasible because they are better suited for treating low-volume gas streams or for use within facility systems rather than in large-volume pipelines like the proposed project. This discussion satisfied NEPA. 130 105. As stated in the discussion of purpose and need above, the Commission does not have the responsibility to analyze broad economic need, for example across the entire Northeast region, and to plan the way that alternative natural gas projects, other energy sources, or energy conservation could satisfy that broad economic need. Further, the Commission cannot require individual energy users to use different or specific energy sources. The EA appropriately described the purpose and need to deliver natural gas to markets in the northeastern United States and Canada. The omission of renewable energy 129 130 EA at 173-174. See, e.g., Am. Gas Ass’n v. FERC, 593 F.3d 14, 19 (D.C. Cir. 2009) (reasoned decision-making requires the Commission to consider alternatives raised by parties or give some reason “within its broad discretion” for declining to do so). Docket Nos. CP15-115-000 and CP15-115-001 - 39 - or increased energy efficiency, which cannot meet this purpose and need, from the EA’s alternatives analysis was reasonable. This discussion also satisfied NEPA. 6. Incomplete Information in the EA 106. The EA notes that information about several topics, such as waterbody crossings, geology, and construction plans is incomplete or forthcoming. Several of the EA’s recommended conditions address this outstanding information. Commenters claim that this information should have been included in the EA to inform the Commission’s analysis and to enable public review. The Conservation Groups contend that without this information the Commission could not adequately analyze project alternatives and could not make a determination whether the project will significantly impact the environment. The groups claim that the missing information also denied the public’s opportunity to meaningfully participate in the NEPA process. 107. We find that the groups’ claims are unsupported. The fact that some analyses, reports, or plans required for the Northern Access 2016 Project have been or will be filed after the issuance of the EA does not undermine the EA’s conclusions or deny meaningful public participation. The EA contains ample information for the Commission to fully consider and address the environmental impacts associated with the Northern Access 2016 Project, including extensive consideration of the potential impacts to water resources. There were numerous opportunities or the public to comment on the projects’ potential impacts. National Fuel and Empire began the pre-filing process to get early stakeholder involvement more than seven months before filing their application. Early opportunities for public involvement included company-sponsored open house meetings, public scoping meetings, and three separate comment periods. 131 Both the environmental resource reports filed with National Fuel’s and Empire’s application as well as the EA put interested parties on notice of the types of activities contemplated and of their potential impacts. Moreover, this order responds to substantive comments filed in response to the EA. Any information that has been for will be filed after the issuance of the EA is accessible to the public in the Commission’s electronic database, eLibrary. 132 Moreover, Environmental Condition 2 in Appendix B to this order delegates authority to the Director of the Office of Energy Projects (OEP) to design and implement any additional measures deemed necessary to ensure continued compliance with the intent of the 131 132 See EA at 2-3. The eLibrary system offers interested parties the option of receiving automatic notification of new filings. Docket Nos. CP15-115-000 and CP15-115-001 - 40 - environmental conditions as well as the avoidance or mitigation of adverse environmental impacts resulting from construction and operation of the projects. 133 7. Direct Impacts a. Water Resources and Wetlands 108. The NYSDEC claims that it is important to address numerous deficiencies in the EA so that the NYSDEC may confidently rely on the EA to inform the agency’s evaluation of National Fuel’s state-level applications, specifically those for a Water Quality Certification under the Clean Water Act and permits under state law to cross or alter streams (Article 15) and wetlands (Article 24) and to withdraw hydrostatic test water. In a letter September 8, 2016, National Fuel submitted a supplement to its joint application to the NYSDEC for these permits. 134 We have reviewed this letter and conclude that its content addresses all of the NYSDEC’s questions and comments about both National Fuel’s application and the Commission’s EA. 109. The FWS recommends the use of trenchless crossing methods for all waterbodies classified as fisheries of special concern. As part of National Fuel’s September 8, 2016 supplement to its joint application for permits submitted to the NYSDEC, National Fuel included a “Trenchless Feasibility Assessment” (Appendix F to that supplement) assessing the possibility of using a trenchless method more broadly across the project. This feasibility assessment documents the criteria considered in evaluating each waterbody and the rationale for why waterbody would or would not be crossed by a trenchless method. We have reviewed this assessment and agree with its conclusions and justifications relating to locations where use of a trenchless crossing method is and is not feasible. 110. The FWS also recommends that alternate crossing methods be developed for each waterbody with a planned horizontal directional drill crossing and that details of those alternate methods be provided to the FWS. We note that the EA includes a recommendation that requires National Fuel to develop alternate crossing plans for waterbodies where a directional drill crossing fails. 135 We have adopted this 133 See Transcontinental Gas Pipe Line Corp., 126 FERC ¶ 61,097, at P 29 (2009) (noting that Environmental Condition 2 includes authority to impose additional mitigation measures). 134 This letter and public attachments were filed in eLibrary on September 13, 2016, with the NYSDEC listed in the description rather than National Fuel. 135 EA at 43. Docket Nos. CP15-115-000 and CP15-115-001 - 41 - recommendation as Environmental Condition 17 in Appendix B to this order. It requires National Fuel to develop these alternate crossing plans in consultation with the U.S. Army Corps of Engineers (Corps) and the FWS. These plans must include mitigation measures to minimize effects on water quality and in-stream resources. 111. The FWS and the NYSDEC express concern about an open-cut crossing of Buffalo Creek. As previously noted, National Fuel has amended its crossing plans and will use the horizontal directional drill method to cross Buffalo Creek. No wet open-cut crossings are proposed for any of the waterbodies crossed by the project. 112. The NYSDEC comments that not all of the wetlands associated with the EMP-03 pipeline were accounted for in the EA, and it suggests that the EA be revised to analyze additional potential impacts. We have evaluated National Fuel’s updated information included in its September 8, 2016 supplement to the joint application to the NYSDEC and the Corps. We acknowledge that additional construction and/or operational impacts are likely for emergent wetlands (increase in construction impacts), scrub-shrub wetlands (increase in operational impacts), and forested wetlands (increase in construction and operational impacts). However, the minor increases in impacts on wetlands along the EMP-03 line do not change the conclusion in the EA that the project will not have significant impacts on wetland resources. 113. The NYSDEC and the FWS express multiple concerns about hydrostatic test water withdrawals. The NYSDEC comments that a water withdrawal permit would be needed and that after testing the water would need to be suitably disposed of. 136 The NYSDEC requests additional information on the impact of withdrawals, flow volumes, and pass-by flows. The FWS comments that the timing and location of water withdrawals could affect rare mussels. In the Erosion and Sediment Control & Agricultural Mitigation Plan (ESCAMP) that National Fuel included with the September 8, 2016 supplement, and in National Fuel’s comments on the EA, National Fuel describes measures it will implement during hydrostatic test water withdrawal and discharge. These measures include screening intakes to avoid fish entrainment, maintaining adequate flow rates to avoid impacts on aquatic life and downstream water use, attaching the intake to a float to avoid stream bed disturbance, and discharging using energy dissipation devices and/or a filter bag (no water would be discharged directly to a waterbody). In response to several comments about the risks of using polluted water for hydrostatic testing, National Fuel no longer proposes to use water from the impaired Bull Creek for testing the EMP-03 pipeline, choosing a municipal water source instead. We have considered National Fuel’s 136 The EA is intended to disclose potential impacts resulting from the project but is not intended to replace the Clean Water Act air permitting process. Docket Nos. CP15-115-000 and CP15-115-001 - 42 - updated information and conclude that the proposed measures will sufficiently protect instream resources, including rare mussels, during withdrawal and discharge. 137 114. The FWS and the NYSDEC comment that at least a conceptual wetland mitigation plan should be provided for public review and that a conclusion related to wetland impacts without such a plan is premature. The EA’s conclusion that wetland impacts would not be significant is based on demonstrated history that pipeline construction rarely results in permanent loss of wetland function and instead more typically only results in minor and temporary impacts. The EA finds that the project may change wetland type from woody vegetation to a more emergent condition. Given that agencies such as the Corps and the NYSDEC regulate wetlands, we defer to those agencies to establish through their permitting mechanisms, to the extent they deem necessary, further mitigation measures that will complement the measures of National Fuel’s ESCAMP and the Commission’s Wetland and Waterbody Construction and Mitigation Procedures (Procedures). To that end, National Fuel provided a detailed conceptual mitigation plan in its September 8, 2016 supplement, which is available for public review in the Commission’s elibrary system. 138 Accordingly, we agree with the EA’s conclusion that the Northern Access 2016 Project is not anticipated to result in significant impacts on wetlands. 115. The NYSDEC comments that the EA lacks reference to the landscape-level avoidance and minimization of wetland impacts achieved through National Fuel’s siting process. The FWS comments that the EA did not “demonstrate a need for the loss of wetlands,” implying that the mitigation hierarchy of avoid, minimize, restore, then compensate was not adequately supported. The FWS further requests that “an adequate alternatives analysis” be provided prior to project approval. We disagree and note that the EPA stated in comments on the EA that the collocation of 69 percent of the project with existing rights-of-way “has minimized the environmental impacts of the project on several resources.” 139 Further discussion regarding the mitigation hierarchy and how National Fuel implemented it was included in National Fuel’s September 8, 2016 supplement. We have reviewed this discussion and find it acceptable. 137 Impacts specific to federally listed species are being considered in our ESA section 7 consultation with the FWS. 138 See the September 13, 2016 filing, Supplement to Joint Application at 5-22 to 5-34 (Section 5.6 Compensatory Mitigation Conceptual Plan). 139 EPA August 29, 2016 Comments on the EA at 1. Docket Nos. CP15-115-000 and CP15-115-001 - 43 - 116. Some commenters, including the Town of Pendleton, expressed concerns regarding impacts on wetlands, most often referencing impacts from construction and operation of the Pendleton Compressor Station. However, both the NYSDEC (in its comments on the EA filed August 26, 2016) and the Corps (in its July 19, 2016 preliminary jurisdictional determination 140) conclude that no state freshwater or federally regulated wetlands will be impacted at the Pendleton Compressor Station site. b. Biological Resources 117. The FWS recommends that National Fuel take additional precautions in waterbodies where dry crossing methods will be implemented and suggests that fish, amphibians, and reptiles be removed from work areas ahead of construction, that flow rates from upstream to downstream of the crossing be maintained at all times, and that National Fuel ensure a slow release of water into the stream behind temporary dams upon completion of work. As discussed in the EA, a dry-ditch crossing does maintain some level of water transport across the crossing location, either via a flume pipe or by using pumps. Larger mobile organisms such as fish, amphibians, and reptiles are generally able to avoid the work area at the onset of construction. Pump intakes are screened to prevent entrainment of smaller, less mobile organisms. As described in its ESCAMP, National Fuel will use pumps to maintain minimal low flow in waterbodies during construction, to the extent practicable. 141 In a configuration using two dams upstream of the crossing site, National Fuel will release water from the downstream temporary dam first to allow water to slowly be reintroduced to the work area before National Fuel removes the upstream dam. We believe these measures are sufficient to protect aquatic resources where dry crossings occur. 118. The FWS indicates that control of invasive non-native plant species is not addressed in the EA and should be required. The FWS further states that invasive plants close to project-disturbed areas should be removed prior to project construction. We clarify here that construction activities, including removal of invasive plants, are not allowed outside of the approved work areas. We note that the EA discusses invasive and noxious weeds, and recommends that National Fuel develop an invasive plant species plan in coordination with the NYSDEC and the Pennsylvania Department of Conservation and Natural Resources. 142 We have added this recommendation as 140 National Fuel August 12, 2016 Supplement to Environmental Information (reproducing the Corps’s July 19, 2016 preliminary jurisdictional determination). 141 EA at App. D, Erosion and Sediment Control & Agricultural Mitigation Plan at 23 and Drawing Number 21. 142 EA at 57-58. Docket Nos. CP15-115-000 and CP15-115-001 - 44 - Environmental Condition 21 in Appendix B to this order. We conclude that this requirement will suitably minimize the spread of invasive and noxious plant species. 119. The FWS requests a thorough analysis of potential fragmentation of interior forest to aid in its analysis of impacts on migratory birds. The FWS specifically notes that the EA included an assessment of such impacts for Pennsylvania but not for New York, 143 resulting in the EA underestimating the level of impact. We disagree. National Fuel proposed a route that is approximately 69 percent collocated with existing linear infrastructure. Collocating with existing rights-of-way may result in a change in edge location, but would not result in new fragmentation of interior forest. The EA shows collocation length by county and finds that approximately 50 percent of the route in Pennsylvania is collocated, whereas almost 80 percent of the mainline route in New York is collocated. 144 Forested lands impacted by the project in New York are either adjacent to existing rights-of-way or are within 300 feet of existing cleared or open areas, thus avoiding new fragmentation of interior forest. 120. More specifically, the mainline route in Allegany and Cattaraugus Counties is approximately 87 and 88 percent collocated, respectively. Only in Erie County does collocation drop below two-thirds of the route (62 percent). When evaluated specifically, the route segments in Erie County that deviate from the existing right-of-way (i.e., are not collocated) are primarily in active agricultural or developed residential lands. Therefore, we conclude that information about interior forest impacts would not materially change with additional analysis in New York. Also, the measures proposed by National Fuel would further minimize impacts in areas where forest lands are crossed. 145 Nonetheless, National Fuel has indicated that it is developing an analysis that it will submit to the FWS to further address the agency’s concerns. 121. The FWS states that no mitigation was provided for loss of migratory bird habitat, disagrees with the EA’s conclusion that impacts on migratory birds will be minor, 146 and recommends that we require National Fuel to provide adequate compensatory mitigation for this loss. The EA provides a robust analysis of potential impacts on migratory birds and discusses mitigation measures that National Fuel would implement to avoid and minimize impacts on this resource, including measures in its Migratory Bird Habitat 143 EA at 57. 144 EA at 7. 145 EA at 57. 146 EA at 72. Docket Nos. CP15-115-000 and CP15-115-001 - 45 - Conservation Plan. The primary measure that National Fuel commits to implement is to focus its clearing activities outside of the primary nesting season. By avoiding direct impacts on active nests, National Fuel will maintain its compliance with the Migratory Bird Treaty Act’s prohibition on take. National Fuel is also currently consulting with the FWS on what additional measures the FWS sees as necessary for protection of this resource. 122. The FWS recommends that we document how facilities change noise levels over current background levels to determine the significance of increased noise affecting wildlife. Although we note that an increase in noise during construction may be disruptive to wildlife occupying habitats near the project, noise levels in those areas will return to background levels during project operation. We do not expect the disruption to have noticeable impacts on resident or migratory wildlife populations. Further, as stated in the EA, National Fuel will design aboveground facilities and use equipment that minimizes potential noise impacts on migratory birds, which would also benefit other local wildlife. 147 123. Pursuant to section 7(a)(2) of the Endangered Species Act, 148 on July 27, 2016, Commission staff requested concurrence from the FWS on staff’s determinations that the Northern Access 2016 Project may affect, but is not likely to adversely affect, the federally threatened northern long-eared bat and rabbitsfoot mussel and the federally endangered rayed bean and clubshell mussels. The FWS’s New York Field Office committed to further coordination with the Commission regarding these species. The FWS did not identify what specific additional information it required to complete consultation, although the FWS did request information related to water withdrawals. 149 In a letter filed November 2, 2016, the Pennsylvania Field Office of the FWS did concur with the Commission’s “may affect, but is not likely to adversely affect” determination for the rayed bean, clubshell, and rabbitsfoot mussels. The agency did not concur, however, with the Commission’s determination that the project “may affect, but is not likely to adversely affect” the northern long-eared bat. Formal consultation with the FWS will proceed and will result in a Biological Opinion to address the project’s potential impact on the northern long-eared bat. As specified in Environmental 147 EA at 71. 148 16 U.S.C. § 1536(a)(2) (2012). 149 In a letter dated June 16, 2016, the FWS’s Pennsylvania Field Office concurred that the Pennsylvania portion of the project is not likely to adversely affect the rabbitsfoot mussel. Docket Nos. CP15-115-000 and CP15-115-001 - 46 - Condition 22 in Appendix B to this order, National Fuel will not be authorized to begin construction until our staff completes section 7 consultation responsibilities with the FWS. c. Socioeconomics and Visual Resources 124. Some commenters contend that property values could decrease in areas next to or near the Pendleton Compressor Station and Wheatfield Dehydration Facility. The installation of these facilities will require temporary workspaces for construction and permanent modifications to property that National Fuel currently owns or will own within the boundaries of each station’s property. Modifications to the Porterville Compressor Station will occur within existing facilities owned by National Fuel. 125. National Fuel’s new Pendleton Compressor Station and Wheatfield Dehydration Facility will, however, introduce new industrial facilities into areas classified as agricultural, rural residential, and urban residential, though these areas are zoned to facilitate industrial development of this kind. As stated in the EA, National Fuel proposes to reduce the impacts on the surrounding properties near the Pendleton Compressor Station by siting the aboveground facilities to make them less conspicuous, developing visual screening, incorporating lighting solutions to reduce nighttime light pollution, planting trees to buffer the compressor station, and installing the facilities within buildings designed to mimic rural farm buildings to blend into the existing surrounding. 150 We note that the EA recommends a condition that we have adopted as Environmental Condition 24 in Appendix B to this order. National Fuel must file its final visual screening plan for the Pendleton Compressor Station, showing the locations of facility components, describing the types and quantities of vegetation screening to be planted, and demonstrating how National Fuel’s building design is consistent with the existing landscape. 126. The EA explains that the potential impact of a pipeline on property values, if any, would be related to many property-specific variables such as the size of the parcel, the parcel’s current value and land use, the value of nearby properties, and would be related to a potential buyer’s specific planned use of the property. 151 As noted in the EA, the Wheatfield Dehydration Facility would be located in an industrial area with ample visual screening from residences to the north of the site. 152 National Fuel’s proposed mitigation 150 EA at 91-92. 151 EA at 100-101. 152 EA at 91. Docket Nos. CP15-115-000 and CP15-115-001 - 47 - will substantially reduce the visual impacts of the Pendleton Compressor Station, thereby minimizing these potential property value impacts. d. Noise 127. The Town of Pendleton suggests that there may be errors in the noise assessment methodologies referenced in the EA that could affect the EA’s conclusions regarding noise impacts and the potential need for noise mitigation at the Pendleton Compressor Station. The town claims that the EA failed to calculate noise impacts on the nearest noise sensitive area and suggests that the nearest noise sensitive area was 538 feet from the proposed Pendleton Compressor Station site. We have reviewed the proximity of noise sensitive areas to the proposed site but have not located the noise sensitive area that the town cites. In fact, the Town of Pendleton’s concern appears to be about an unconstructed residence that would be part of a residential development not yet under official consideration by the town as a land use action, thereby not warranting consideration during our review of National Fuel’s project. 128. The Town of Pendleton further asserts that the background sound study “departs from applicable methods for evaluating long-term background sound levels published by the Acoustical Society of America (ASA) and the American Natural Standards Institute (ANSI).” We disagree with this assertion. The noise analysis provided in the project application used proper engineering practice and followed applicable standards for a study of this type. As discussed in the EA, we require that noise levels generated by a proposed new compressor station or by the combination of an existing station and expansion facilities may not exceed a day-night sound level (Ldn) of 55 decibels on the Aweighted scale (dBA) at any pre-existing noise sensitive area. 153 The analysis discussed in the EA demonstrates that the Pendleton Compressor Station would meet this requirement. 129. In order to ensure noise impacts remain below threshold levels, we are including a recommendation from the EA as Environmental Condition 27 in Appendix B of this order to require that National Fuel perform noise surveys within 60 days of startup for its new and modified stations. The condition further requires National Fuel to demonstrate compliance with the Ldn of 55 dBA noise criterion by taking noise measurements at a point near the identified nearest noise sensitive areas. Commission staff will review the results of all such surveys to ensure their adequacy, including the chosen measurement locations and methodology. This will ensure that there is no significant impact on the environment from project-related noise. 153 EA at 118. Docket Nos. CP15-115-000 and CP15-115-001 e. - 48 - Air Quality 130. National Fuel suggests that the project’s aboveground facilities would not require certain air permits, given the design, emissions, and NGA-jurisdictional status of the project. The NYSDEC disagreed. As discussed in the EA, the project is subject to the NYSDEC’s facility air regulations. 154 The NYSDEC has the authority to review and approve all design, permitting, and pollution control aspects of the compressor units at the Porterville and Pendleton Compressor Stations, independent of the Commission’s review. 155 The air quality analysis in the EA went further than the NYSDEC’s permit review requires. For example, National Fuel conducted air quality impact modeling for the project, although this modeling is not required where a project sponsor will install the controls that National Fuel has committed to install. The modeling for the Northern Access 2016 Project compressor stations indicates that the conservatively modeled impacts attributable to the compressor stations would remain well below (less than half of) the National Ambient Air Quality Standards (NAAQS) for regulated pollutants, and air impacts would decrease in relation to the distance from the compressor stations. 156 Regardless, under Environmental Condition 22 in Appendix B to this order National Fuel must obtain all federally delegated state permits before it can construct and operate the project. These may include Minor Facility Registrations or State Facility Permits and authorizations. 131. Some commenters suggest that certain potential air quality control measures were not considered for the project and that values in the EA underestimate potential impacts on air quality. The EA disclosed potential air quality impacts associated with the project as proposed. Based upon the air quality analysis completed for the project, the impacts were determined to be within safe levels and below EPA-established benchmarks. 132. The EA is intended to disclose potential impacts resulting from the project but is not intended to replace the Clean Air Act air permitting process. The methodology to calculate emissions is established by the air permitting authority, which, in the case of the new Pendleton Compressor Station, is the NYSDEC. We find that the EA appropriately disclosed potential impacts associated with the operational emissions from the project, including the Pendleton Compressor Station. 154 EA at 21. 155 N.Y. Comp. Codes R. & Regs. tit. 6, pt. 201 (2016) (Permits and Registrations). 156 See National Fuel Nov. 19, 2015 Ambient Sound Survey. Docket Nos. CP15-115-000 and CP15-115-001 - 49 - 133. Several commenters imply that the EA failed to consider numerous public comments alleging that the project’s air emissions would harm human health. Other commenters express concern that the health impacts attributable to the project, though identified within the EA, were not adequately assessed. The EA concludes that the modeled emissions from normal operations and blowdown events from the new Pendleton Compressor Station and Wheatfield Dehydration Facility, as well as the modified Porterville Compressor Station, would be below a level that could present health concerns. 157 We agree. 8. Historic and Archaeological Resources 134. Several commenters raise concerns about project construction potentially affecting historic and archaeological resources. The EA summarizes the efforts undertaken to identify such resources within an area of potential effect that includes and surrounds the project construction area. 158 These efforts were consistent with state and federal regulations and were reviewed by both Commission staff and the state historic preservation offices for Pennsylvania and New York. Through these reviews, measures necessary to protect historic and archaeological resources were identified, including route adjustments, such that significant impacts on these resources are not expected. Further, National Fuel developed Unanticipated Discovery Plans to address resources found during construction that have not been previously identified. The EA reviewed these plans and found them acceptable. 159 We agree. 9. Greenhouse Gases 135. The EA broadly discusses how climate change might affect the Northern Access 2016 Project and acknowledges that the project’s greenhouse gas emissions would contribute to climate change. 160 The EA quantifies the project’s direct greenhouse gas (GHG) emissions during construction to be 2,530 metric tons per year of carbon dioxide equivalents (tpy CO2e). 161 The EA also quantifies the project’s direct GHG emissions 157 EA at 112-118. 158 EA at 92-97. 159 EA at 95. 160 EA at 109-110. 161 EA at 110, 112 tbl.B.8.a-4. Docket Nos. CP15-115-000 and CP15-115-001 - 50 - during operation, including: 7,097 and 6,450 tpy CO2e from pipeline equipment, 162 22,480 tpy CO2e from the modified Porterville Compressor Station, 163 97,668 tpy CO2e from the new Pendleton Compressor Station, 164 and 4,426 tpy CO2e from the new Wheatfield Dehydration Facility. 165 136. Commenters oppose the project on the basis that its operation would produce GHG emissions and result in irreversible impacts on the global climate. We acknowledge that construction and operation of the project will result in both short- and long-term GHG emissions over the project’s lifetime. 137. On August 8, 2016, Oil Change International 166 filed comments, consisting of one paragraph and an attached 32-page report, in 11 pipeline certificate proceedings, including this proceeding. Oil Change International asserts that there should be a climate test for all natural gas infrastructure, that, in light of CEQ’s 2016 GHG Guidance, “the alignment of natural gas infrastructure permitting with national climate goals and plans should become a priority for FERC and other federal government agencies,” and that the Commission should “conduct full Greenhouse Gas impact analysis as part of the NEPA process for all listed projects.” 167 The report asserts generally that increased U.S. natural gas production in the Appalachian Basin is not consistent with safe climate goals, and that proposed pipeline projects will increase takeaway capacity from the basin and provide long term financial incentives for increased production and consumption of natural gas. 138. The comments and study filed by Oil Change International provide no specific information about the Northern Access 2016 Project and thus do not assist us in our 162 EA at 115 tbl.B.8.a-7 and tbl.B.8.a-8. 163 EA at 114 tbl.B.8.a-5. 164 EA at 114 tbl.B.8.a-6. 165 Id. 166 Oil Change International filed comments on behalf of the Sierra Club, Earthworks, Appalachian Voices, Chesapeake Climate Action, 350.org, Bold Alliance, Environmental Action, Blue Ridge Environmental Defense League, Protect Our Water, Heritage and Rights (Virginia & West Virginia), Friends of Water, Mountain Lakes Preservation Alliance, Sierra Club West Virginia, and Sierra Club Virginia. 167 Oil Change International August 8, 2016 Comments on the EA at 1. Docket Nos. CP15-115-000 and CP15-115-001 - 51 - analysis. As discussed above, we indeed do analyze the greenhouse gas impacts of proposed projects as part of our NEPA and NGA review. 139. As to the more global issues raised, while the Commission does not utilize a specific “climate test,” we do examine the impacts of the projects before us, including impacts on climate change. Under NEPA, we are required to take a “hard look” at the environmental impacts of the proposed project and we have done so. To the extent that Oil Change International suggests an alignment of project permitting with national climate change goals, we note that it is for Congress, the Executive Branch, and agencies with jurisdiction over broad environmental issues to establish such goals; our role under the NGA is considerably more limited, and we have no authority to establish national environmental policy. 140. The EPA suggests that the Council on Environmental Quality’s (CEQ) August 1, 2016 Final Guidance on the Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in NEPA Reviews be used to better understand GHG emissions from the project. The EPA further recommends that the EA estimate emissions from methane leakage and indirect emissions associated with production and combustion of natural gas brought into production as an indirect effect of the project. The EPA also comments that the EA did not disclose measures considered to avoid, minimize, or mitigate for GHG emissions. 141. We note that the CEQ guidance on GHG emissions and climate change, published on August 1, 2016, was not available for reference when Commission staff released the EA for the Northern Access 2016 Project on July 27, 2016. In general, the CEQ guidance recommends that an agency quantify a project’s direct and indirect GHG emissions, consider GHG emissions in the alternatives analysis, and propose reasonable mitigation measures related to climate change in line with the project need. 142. We quantify the project’s emissions above. With the exception of the no-action alternative, the reasonable alternatives identified in the EA would not generate a significantly different amount of GHG emissions compared to the proposed project. The level of analysis completed in the EA is sufficient given the scope of the project. Neither the no-action alternative nor any system alternative was found to have a significant environmental advantage over the project while also meeting National Fuel’s stated purpose. 168 We confirm these findings. Further, the EA does identify mitigation measures to be implemented at project facilities. 168 EA at 162. Docket Nos. CP15-115-000 and CP15-115-001 - 52 - 143. Commenters, including the NYSDEC, suggest that a gas recapture system should be considered to reuse gas released during blowdowns of the new Pendleton Compressor Station. Subpart OOOOa of the recently revised New Source Performance Standards for certain new and modified sources in the oil and natural gas industries already regulates emissions of GHGs and volatile organic compounds (VOC). 169 Subpart OOOOa requires implementation of leak detection and repair programs at applicable natural gas compressor stations, requirements to limit GHG and VOC emissions from compressors and pneumatic controllers used at compressor stations, and includes requirements for recordkeeping and annual reporting. National Fuel is required to comply with the applicable portions of Subpart OOOOa by installing compliant equipment at the new and modified compressor stations and by implementing leak detection and repair programs. These controls obviate the need for an additional gas recapture system to mitigate blowdowns. 10. Indirect Impacts of Natural Gas Production 144. The Conservation Groups and Sierra Club broadly criticize the EA for failing to consider the indirect effects of shale gas development to supply the Northern Access 2016 Project. The Commission addressed very similar objections to the Niagara Expansion Project and Northern Access 2015 Project in Docket Nos. CP14-88-001 and CP14-100-001. 170 For the same reasons, we again reject these arguments as detailed below. 145. The CEQ regulations direct federal agencies to examine the direct, indirect, and cumulative impacts of proposed actions. 171 Indirect impacts are defined as those: . . . which are caused by the action and are later in time or farther removed in distance [than direct impacts], but are still reasonably foreseeable. Indirect effects may include growth inducing effects and other effects related to induced changes in the pattern of land use, population density or growth rate, 169 Oil and Natural Gas Sector: Emissions Standards for New, Reconstructed, and Modified Sources, 81 Fed. Reg. 35,824 (June 3, 2016) (amending standards at 40 C.F.R. pt. 60, subpt. OOOO, and establishing new standards to be codified at 40 C.F.R. pt. 60, subpt. OOOOa). 170 See Tennessee Gas Pipeline Co., L.L.C., 154 FERC ¶ 61,184, at PP 54-73 (2016). 171 40 C.F.R. § 1508.25(c) (2016). Docket Nos. CP15-115-000 and CP15-115-001 - 53 - and related effects on air and water and other natural systems, including ecosystems. 172 Accordingly, to determine whether an impact should be studied as an indirect impact, the Commission must determine whether it is both (1) caused by the proposed action and (2) reasonably foreseeable. 146. With respect to causation, “NEPA requires ‘a reasonably close causal relationship’ between the environmental effect and the alleged cause” 173 in order “to make an agency responsible for a particular effect under NEPA.” 174 As the Supreme Court explained, “a ‘but for’ causal relationship is insufficient [to establish cause for purposes of NEPA].” 175 Thus, “[s]ome effects that are ‘caused by’ a change in the physical environment in the sense of ‘but for’ causation,” will not fall within NEPA if the causal chain is too attenuated. 176 Further, the Court has stated that “where an agency has no ability to prevent a certain effect due to its limited statutory authority over the relevant actions, the agency cannot be considered a legally relevant ‘cause’ of the effect.” 177 147. An effect is “reasonably foreseeable” if it is “sufficiently likely to occur that a person of ordinary prudence would take it into account in reaching a decision.” 178 NEPA 172 Id. § 1508.8(b). 173 U.S. Dep’t of Transp. v. Pub. Citizen, 541 U.S. 752 at 767 (2004) (quoting Metro. Edison Co. v. People Against Nuclear Energy, 460 U.S. 766, 774 (1983)). 174 Id. 175 Id.; see also Freeport LNG, 827 F.3d at 46 (FERC need not examine everything that could conceivably be a but-for cause of the project at issue); Sierra Club v. FERC, 827 F.3d 59, 68 (D.C. Cir. 2016) (Sabine Pass LNG) (FERC order authorizing construction of liquefied natural gas export facilities is not the legally relevant cause of increased production of natural gas). 176 Metro. Edison Co., 460 U.S. at 774. 177 Pub. Citizen, 541 U.S. at 770; see also Freeport LNG, 827 F.3d at 49 (affirming that Public Citizen is explicit that FERC, in authorizing liquefied natural gas facilities, need not consider effects, including induced production, that could only occur after intervening action by the DOE); Sabine Pass LNG, 827 F.3d at 68 (same); EarthReports, Inc. v. FERC, 828 F.3d 949, 955-56 (D.C. Cir. 2016) (same). 178 Sierra Club v. Marsh, 976 F.2d 763, 767 (1st Cir. 1992). See also City of (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 54 - requires “reasonable forecasting,” but an agency is not required “to engage in speculative analysis” or “to do the impractical, if not enough information is available to permit meaningful consideration.” 179 148. We have previously concluded in natural gas infrastructure proceedings, based on the specifics of the project being proposed in each proceeding, that the environmental effects resulting from natural gas production are generally neither sufficiently causally related to specific natural gas infrastructure projects nor are the potential impacts from gas production reasonably foreseeable such that the Commission could undertake a meaningful analysis that would aid our determination. 180 i. Causation 149. The Conservation Groups and Sierra Club argue that the Commission has specific information in this proceeding sufficient to show a causal link between the project and natural gas production in Seneca Resources’ “Western Development Area” in Pennsylvania where the project will receive gas. 181 Generally, the Conservation Groups cite statements by a trade association, business executives, a town newspaper, and the Energy Information Administration suggesting both that insufficient transportation infrastructure can limit production growth and that additional transportation infrastructure spurs production growth. Specifically, the Conservation Groups cite statements by National Fuel in its application for the project, in press releases from 2014 and 2016, and in a PowerPoint presentation to investors in 2016 that they believe (a) suggest a link between Seneca Resources’ future production and the transportation capacity created by the Northern Access 2015 and 2016 Projects and (b) identify a specific subset of well sites poised for development that will supply gas to be transported on the 2016 project. Shoreacres v. Waterworth, 420 F.3d 440, 453 (5th Cir. 2005). 179 Northern Plains Res. Council, Inc. v. Surface Transp. Bd., 668 F.3d 1067, 1078 (9th Cir. 2011). 180 See, e.g., Central New York Oil and Gas Co., LLC, 137 FERC ¶ 61,121, at PP 81-101 (2011), order on reh’g, 138 FERC ¶ 61,104, at PP 33-49 (2012), petition for review dismissed sub nom. Coal. for Responsible Growth v. FERC, 485 Fed. Appx. 472, 474-75 (2d Cir. 2012) (unpublished opinion). 181 Conservation Groups August 29, 2016 Comments on the EA for the Northern Access 2016 Project at 16-22. Docket Nos. CP15-115-000 and CP15-115-001 - 55 - 150. National Fuel acknowledges that Seneca Resources entered into a Joint Development Agreement with another producer to develop specific shale resources in the Clermont/Rich Valley area (within Seneca Resources’ Western Development Area) that will use the transportation capacity created by the Northern Access 2015 and 2016 Projects. The Conservation Groups assert that regardless of when these wells are drilled, Seneca Resources has many wells that are “drilled but uncompleted.” Seneca Resources will only be induced to complete these wells and place them into production, the groups argue, if the Northern Access 2016 Project is approved. The Conservation Groups claim that the environmental impacts of this induced second-phase completion and production must be analyzed in the Commission’s NEPA document. 151. In order to identify the appropriate scope of the Commission’s environmental review, in June 2016, Commission staff submitted a data request to National Fuel about the wells subject to the Joint Development Agreement. National Fuel responded that the drilling of the 75 wells (with the option for one additional 7-well pad) identified in the Joint Development Agreement “is not contingent upon any milestone in the regulatory process for the Northern Access 2016 Project” and will move forward without assurance that a certificate will issue. 182 National Fuel explains that the 75 wells will be drilled from 10 well pads (plus an option to develop one additional 7-well well pad, totaling 82 wells). Of these, the closest well pad is 5.57 miles from the Northern Access 2016 Project’s receipt point. As of June 23, 2016, National Fuel reported that 20 of the 75 wells (or 27 of the 82) remain to be drilled and are expected to be drilled by February 2017, 9 months before the project’s anticipated in-service date. 183 152. On September 20, 2016, National Fuel provided an update on Seneca’s production activities and reported that 63 wells have been drilled under the Joint Development Agreement (i.e., only 12 of the 75 or 19 of the 82 remain to be drilled). 184 National Fuel also refutes the Conservation Groups’ unsupported claim that Seneca Resources is waiting for the Northern Access 2016 Project before Seneca Resources completes and produces existing drilled wells. National Fuel notes that Seneca Resources has completed 46 of the 63 drilled wells. 153. National Fuel’s response to Commission staff’s data request supports the Commission’s conclusion that natural gas development under the Joint Development 182 National Fuel June 23, 2016 Response to Environmental Data Request. 183 Id. 184 National Fuel September 20, 2016 Motion for Leave to Answer and Answer, app. B at 15-16. Docket Nos. CP15-115-000 and CP15-115-001 - 56 - Agreement will precede the Northern Access 2016 Project and does not rely on it, even if the development would benefit from the project if it goes forward. This does not show a causal connection (i.e. that the project induced Seneca to drill the wells that are the subject of the Joint Development Agreement) sufficient to require analysis of this development under NEPA as an indirect impact. But to the extent that any activities under the Joint Development Agreement have a potential cumulative impact with the Northern Access 2016 Project, that potential cumulative impact was analyzed in the EA’s cumulative impact section, discussed further below. 154. As we note above, a causal relationship sufficient to warrant Commission analysis of the non-pipeline activity as an indirect impact would only exist if a proposed pipeline would transport new production from a specified production area and that production would not occur in the absence of the proposed pipeline (i.e., there will be no other way to move the gas). 185 Though the Conservation Groups disagree with our position, we continue to believe that the opposite causal relationship is in fact more likely, i.e., once production begins in an area, shippers or end users will support the development of a pipeline to move the produced gas. 155. The evidence in the record, including the press releases and marketing statements cited by the Conservation Groups, does not demonstrate the requisite reasonably close causal relationship between the Northern Access 2016 Project and the impacts of future natural gas production to necessitate further analysis. 186 156. National Fuel Gas Company’s statements about the relationship between its production arm and its transportation arm show only that the parent company expects that its production will grow, that its transportation capacity will grow, and that growing production will benefit from growing transportation. 187 The statements do not indicate 185 See cf. Sylvester v. U.S. Army Corps of Eng’rs, 884 F.2d 394, 400 (9th Cir. 1989) (upholding the environmental review of a golf course that excluded the impacts of an adjoining resort complex project). See also Morongo Band of Mission Indians v. FAA, 161 F.3d 569, 580 (9th Cir. 1998) (concluding that increased air traffic resulting from airport plan was not an indirect, “growth-inducing” impact); City of Carmel-by-the-Sea v. U.S. Dep’t of Transp., 123 F.3d 1142, 1162 (9th Cir. 1997) (acknowledging that existing development led to planned freeway, rather than the reverse, notwithstanding the project’s potential to induce additional development). 186 Minisink Residents for Envtl. Preservation v. FERC, 762 F.3d at 108 (affirming the Commission’s rejection of a pipeline company’s PowerPoint presentation as “merely a marketing document”). 187 National Fuel Gas Company is the parent company of National Fuel and (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 57 - that the transportation capacity proposed in this proceeding is an essential predicate for production growth or that transportation capacity must precede production growth. The statements do not prove causation as contemplated by CEQ’s regulations. Moreover, the Commission has consistently found that our knowledge that specific producers will be shippers on a proposed pipeline does not, by itself, bring the impacts of production into our NEPA review. 188 157. The fact that natural gas production and transportation facilities are all components of the general supply chain required to bring domestic natural gas to market is not in dispute. This does not mean, however, that the Commission’s approval of this particular infrastructure project will cause or induce the effect of additional or further shale gas production. As we have explained in other proceedings, a number of factors, such as domestic natural gas prices and production costs, drive new drilling. 189 If the Northern Access 2016 Project were not constructed, it is reasonable to assume that any new production spurred by such factors, including any such production by Seneca Resources, would reach intended markets through alternate pipelines or other modes of Seneca Resources. 188 See, e.g., Dominion Cove Point LNG, LP, 148 FERC ¶ 61,244 (2014); Texas Eastern Transmission, LP, 139 FERC ¶ 61,138, at PP 70-73, order on reh’g, 141 FERC ¶ 61,043, at PP 37-41 (2012); Tennessee Gas Pipeline Co., L.L.C., 139 FERC ¶ 61,161, at PP 178-200, order on reh’g, 142 FERC ¶ 61,025, at PP 72-87 (2012), rev’d on other grounds, Delaware RiverKeeper Network v. FERC, 753 F.3d 1034 (D.C. Cir., 2014); Transcontinental Gas Pipe Line Co., LLC, 141 FERC ¶ 61,091, at PP 127-141 (2012), order on reh’g, 143 FERC ¶ 61,132, at PP 49-60 (2013). 189 Rockies Express Pipeline LLC, 150 FERC ¶ 61,161, at P 39 (2015) (Rockies Express). See also Sabine Pass LNG, 827 F.3d at 68-69 (finding that FERC adequately explained why it was not reasonably foreseeable that its authorization of greater capacity at an LNG export terminal would induce additional domestic natural gas production); Sierra Club v. Clinton, 746 F. Supp. 2d 1025, 1045 (D. Minn. 2010) (holding that the U.S. Department of State, in its environmental analysis for an oil pipeline permit, properly decided not to assess the transboundary impacts associated with oil production because, among other things, oil production is driven by oil prices, concerns surrounding the global supply of oil, market potential, and cost of production); Florida Wildlife Fed’n v. Goldschmidt, 506 F. Supp. 350, 375 (S.D. Fla. 1981) (ruling that an agency properly considered indirect impacts when market demand, not a highway, would induce development). Docket Nos. CP15-115-000 and CP15-115-001 - 58 - transportation. 190 Again, any such production would take place pursuant to the regulatory authority of state and local governments. 191 The Northern Access 2016 Project is responding to the need for transportation, not creating it. 158. The situation here is similar to that in Central New York Oil and Gas Co., LLC. 192 There, the Commission authorized construction and operation of the 39-mile-long MARC I Hub Line Project, which traversed Northeast Pennsylvania, and was intended, in part, to “provide access to interstate markets for natural gas produced from the Marcellus [s]hale in northeast Pennsylvania . . . .” 193 The Commission concluded that the pipeline was not sufficiently causally related to upstream production, a conclusion affirmed by the Second Circuit, in part because producers or developers of gathering facilities could simply build longer gathering lines to connect wells in the three counties crossed by that project to existing interstate pipelines, with no Commission regulation or NEPA oversight. 194 159. Here, a network of transmission facilities already exists through which Seneca Resources could arrange to move its produced gas from the Western Development Area to local users or into the interstate pipeline system. For example, as noted in the EA, the site for the Northern Access 2016 Project’s southern terminus is an existing Producer Interconnect Station where the Clermont Gathering System already connects to Tennessee’s 300 Line. 195 National Fuel Gas Company’s 2016 Investor PowerPoint, cited by the Conservation Groups, similarly indicates that the existing Clermont Gathering System already interconnects with Tennessee’s 300 Line and with National Fuel’s existing pipeline system, while also crossing Dominion Transmission’s existing system. 190 Rockies Express, 150 FERC ¶ 61,161 at P 39. 191 See N.J. Dep’t of Envtl. Prot. v. U.S. Nuclear Regulatory Comm’n, 561 F.3d 132, 139 (3d Cir. 2009) (NEPA does not require consideration of foreseeable effects that are not potentially subject to the control of the federal agency doing the evaluation). 192 Central New York Oil & Gas Co., 137 FERC ¶ 61,121, order on reh’g, 138 FERC ¶ 61,104 (2012), aff’d sub nom. Coal. for Responsible Growth & Res. Conservation v. FERC, 485 F. App’x 472 (2d Cir. 2012) (unpublished opinion). 193 Central New York Oil & Gas Co., 138 FERC ¶ 61,104 at P 5. 194 Central New York Oil & Gas Co., 137 FERC ¶ 61,121, at P 91; see also Coal. for Responsible Growth & Res. Conservation v. FERC, 485 F. App’x at 474 (unpublished opinion). 195 EA at 9. Docket Nos. CP15-115-000 and CP15-115-001 - 59 - National Fuel’s system more broadly interconnects with Tennessee’s 200 Line and the existing systems of Empire Pipeline and Millennium Pipeline. The PowerPoint also indicates that National Fuel Gas Company’s gathering subsidiary already intends to expand its Clermont Gathering System from 66 miles of existing pipeline and 26,220 horsepower of compression to more than 300 miles of pipeline and more than 60,000 horsepower of compression. 196 This shows yet another way that Seneca Resources could move its gas to market without the construction of the Northern Access 2016 Project, which underscores that the project is not an essential predicate for any additional natural gas production activities. ii. Reasonable Foreseeability 160. The Conservation Groups incorrectly assert that the Commission has found incremental natural gas production to be unforeseeable. 197 Rather, the Commission has found that the potential environmental impacts resulting from such production are generally not reasonably foreseeable. Because production-related impacts are highly localized, even if the Commission knows the general source area of gas likely to be transported on a given pipeline, a meaningful analysis of production impacts would require more detailed information regarding the number, location, and timing of wells, roads, gathering lines, and other appurtenant facilities, as well as details about production methods, which can vary by producer and which depend on the applicable regulations in the various states. Accordingly, to date, the impacts of natural gas production are not reasonably foreseeable because they are “so nebulous” that we “cannot forecast [their] likely effects” in the context of an environmental analysis of the impacts related to construction and modification of natural gas pipeline facilities. 198 161. The Conservation Groups contend that the impacts of shale gas development induced by the project is reasonably foreseeable because National Fuel Gas Company has admitted that gas for the Northern Access 2016 Project will originate from the Clermont/Rich Valley area in northeastern part of Seneca Resources Western Development Area in Cameron, Elk, and McKean Counties, Pennsylvania and because the 75 wells identified for development under the Joint Agreement provide a targeted subset of development activities for analysis. 196 National Fuel Gas Company 2016 Investor PowerPoint at 13. 197 Conservation Groups Comments on the EA at 27-28. 198 Habitat Educ. Ctr. v. U.S. Forest Serv., 609 F.3d 897, 902 (7th Cir. 2010) (agency need not discuss projects too speculative for meaningful discussion). Docket Nos. CP15-115-000 and CP15-115-001 - 60 - 162. The groups emphasize that speculation is implicit in NEPA, there is no need to know the precise location, scale, scope, and timing of shale gas drilling. 199 As evidence of reasonably foreseeable production impacts, the Conservation Groups cite reports by the U.S. Geological Survey (USGS) and by the Nature Conservancy extrapolating environmental impacts of continuing shale gas development. 200 163. We disagree. Even accepting, arguendo, that the project would induce gas production in addition to the wells already drilled under the Joint Development Agreement, the impacts are still not reasonably foreseeable. Even knowing, as here, the identity of a producer of gas to be shipped on a pipeline, and the general area where that producer's existing wells are located, does not alter the fact that the number and location of any induced additional wells are matters of speculation. The Conservation Groups acknowledge this uncertainty in their argument that regardless when Seneca Resources drills a well, the completion and production of that well may occur much later in the future. Given that factors such as market prices and production costs, among others, drive new drilling, combined with the highly localized impacts of production, any forecasting can only be a general estimate. A broad analysis, based on generalized assumptions rather than reasonably specific information of this type, will not meaningfully assist the Commission in its decision making, e.g., evaluating potential alternatives. 201 We have previously rejected the Conservation Groups’ cited reports from the USGS and the Nature Conservancy for this reason. 202 While Northern Plains Resource Council v. Surface Transportation Board states that speculation is implicit in NEPA, it also states that agencies are not required “to do the impractical, if not enough information is available to permit meaningful consideration.” 203 199 Conservation Groups Comments on the EA at 36-40. 200 Id. at 28. 201 See, e.g., Habitat Educ. Ctr. v. U.S. Forest Serv., 609 F.3d 897 (7th Cir. 2010) (holding that an agency does not fail to give a project a “hard look” for purposes of NEPA simply because it omits from discussion a future project so speculative that the agency can say nothing meaningful about its cumulative effects). 202 E.g., Empire Pipeline, Inc., 153 FERC ¶ 61,379, at PP 67 n.108, 73 n.126 (2015). 203 Northern Plains Resource Council, Inc. v. Surface Transp. Bd., 668 F.3d at 1078 (citing Envtl. Prot. Info. Ctr. v. U.S. Forest Serv., 451 F.3d 1005, 1014 (9th Cir. 2006)). See also The Fund for Animals v. Kempthorne, 538 F.3d 124, 137 (2d Cir. 2008) (speculation in an EIS is not precluded, but the agency is not obliged to engage in endless (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 61 - 164. The potential impacts of natural gas production, with the exception of greenhouse gases and climate change, are localized. We are aware of no forecasts by states, in particular Pennsylvania where the project is located, or other entities, which would enable the Commission to meaningfully predict the highly localized production-related impacts. Each locale includes unique conditions and environmental resources. Production activities are thus regulated at a state and local level. It is the states, rather than the Commission, who would be most likely to have specific information regarding future production. PA Department of Environmental Protection, for example, has developed best management practices for the construction and operation of upstream oil and gas production facilities in Pennsylvania. PA Department of Environmental Protection and the Susquehanna River Basin Commission have also enacted regulations to specifically protect water resources from potential impacts associated with the development of the Marcellus Shale region. In addition, certain activities are subject to federal regulation. For example, deep underground injection and disposal of wastewaters and liquids are subject to regulation by the EPA under the Safe Drinking Water Act. The EPA also regulates air emissions under the Clean Air Act. On public lands, federal agencies are responsible for the enforcement of regulations that apply to natural gas wells. 165. Nonetheless, we note that although not required by NEPA, a number of federal agencies have generally examined the potential environmental issues associated with unconventional natural gas production in order to provide the public with a more complete understanding of the potential impacts. The DOE has concluded that such production, when conforming to regulatory requirements, implementing best management practices, and administering pollution prevention concepts, may have temporary, minor impacts on water resources. 204 EPA has concluded that hydraulic fracturing can impact drinking water resources under some circumstances and identified conditions under which impacts from hydraulic fracturing activities can be more frequent or severe. 205 With respect to air quality, the DOE found that natural gas development hypothesizing as to remote possibilities). 204 U.S. Department of Energy, Addendum to Environmental Review Documents Concerning Exports of Natural Gas from the United States (Aug. 2014) (DOE Addendum), http://energy.gov/sites/prod/files/2014/08/f18/Addendum.pdf. See also Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands, 80 Fed. Reg. 16,128, 16,130 (Mar. 26, 2015) (U.S. Bureau of Land Management promulgated regulations for hydraulic fracturing on federal and Indian lands to “provide significant benefits to all Americans by avoiding potential damages to water quality, the environment, and public health”). 205 See U.S. EPA, Hydraulic Fracturing for Oil and Gas: Impacts from the (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 62 - leads to both short- and long-term increases in local and regional air emissions. 206 It also found that such emissions may contribute to climate change. 207 But to the extent that natural gas production replaces the use of other carbon-based energy sources, the DOE found that there may be a net positive impact in terms of climate change. 208 166. The Conservation Groups cite Mid States Coalition for Progress v. Surface Transportation Board, 209 in which the Eighth Circuit Court of Appeals stated that, “when the nature of the effect is reasonably foreseeable but its extent is not, [an] agency may not simply ignore the effect.” 210 The groups’ reliance on Mid States is unavailing. The EA did not ignore the effects of natural gas development. The cumulative impact analysis considered the nature of impacts from this development within McKean County, Pennsylvania, where the project’s southern terminus and 27 miles of pipeline are located. 211 New York has a moratorium on shale gas development. Specifically, the EA considered the potential cumulative impacts of natural gas development on soil and geology, water resources, land use and visual resources, and air quality, climate change, and noise. 212 167. In the Mid States case, the agency acknowledged that a particular outcome was reasonably foreseeable—increased usage of 100 million tons of coal at coal-burning Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States, at ES3-4 (Dec. 2016) (final report), http://ofmpub.epa.gov/eims/eimscomm.getfile?p_download_id=529930 (finding significant data gaps and uncertainties in the available data prevented EPA from calculating or estimating the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle). 206 DOE Addendum at 32. 207 Id. at 44. 208 Id. 209 345 F.3d 520 (8th Cir. 2003) (Mid States). 210 Mid States, 345 F.3d. at 549. 211 EA at app. G, G-5 tbl.G-2 (see row for “Oil and Natural Gas Wells and gathering lines”). 212 EA at 139-160. Docket Nos. CP15-115-000 and CP15-115-001 - 63 - electric generation plants resulting from the availability of cheaper coal after the new rail lines were built—but then failed to consider its impact. 213 In particular, the court in Mid States faulted the agency for failing to consider the environmental effects of the known increase in coal usage where the agency had already identified the nature of the ensuing environmental effects. 214 Here, we do not concede the causal relationship, and even if we were to assume a causal relationship for argument, the EA did analyze the nature of effects from natural gas development near the project area even though the extent of the effect is not reasonably foreseeable. 215 Specifically, even if additional gas were induced, the amount, timing, and specific location of such development activity is speculative. 216 Thus, unlike the agency in Mid States, here we are not “simply ignor[ing]” the impacts of future gas development; rather, there are no identified “specific and causally linear indirect consequences that could reasonably be foreseen and factored into the Commission’s environmental analysis.” 217 11. Cumulative Impacts 168. CEQ defines cumulative impacts as “the impact on the environment that results from the incremental impact of the action when added to other past, present, and reasonably foreseeable future actions.” 218 The requirement that an impact must be “reasonably foreseeable” to be considered in a NEPA analysis applies to both indirect and cumulative impacts. 213 Mid States, 345 F.3d. at 549-50; see also Freeport LNG, 827 F.3d at 48 (finding that Mid States “looks nothing like” challenge that FERC failed to consider indirect impacts claimed increased natural gas production stemming FERC’s authorization of liquefied natural gas export facilities). 214 Id. at 549. 215 EA at 139-160. 216 See generally Nat. Res. Def. Council, Inc. v. Callaway, 524 F.2d 79, 90 (2d Cir. 1975) (holding that an agency need not “consider other projects so far removed in time or distance from its own that the interrelationship, if any, between them is unknown or speculative”). 217 Freeport LNG, 827 F.3d at 47. 218 40 C.F.R. § 1508.7 (2016). Docket Nos. CP15-115-000 and CP15-115-001 - 64 - 169. The “determination of the extent and effect of [cumulative impacts], and particularly identification of the geographic area within which they may occur, is a task assigned to the special competency of the appropriate agencies.” 219 CEQ has explained that “it is not practical to analyze the cumulative effects of an action on the universe; the list of environmental effects must focus on those that are truly meaningful.” 220 Further, a cumulative impact analysis need only include “such information as appears to be reasonably necessary under the circumstances for evaluation of the project rather than to be so all-encompassing in scope that the task of preparing it would become either fruitless or well-nigh impossible.” 221 An agency’s analysis should be proportional to the magnitude of the environmental impacts of a proposed action; actions that will have no significant direct and indirect impacts usually require only a limited cumulative impacts analysis. 222 170. The Conservation Groups, the Niagara Chapter of the Sierra Club, and EPA raise related claims that the EA fails to take a hard look at the cumulative impact resulting from the Northern Access 2016 Project because the EA uses arbitrarily narrow geographic boundaries for analysis of potential cumulative impacts to several affected resources. The Conservation Groups object to the EA’s assumptions that the impacts of other past, present, and reasonably foreseeable actions will be reduced through measures required under applicable federal and state permits. The Conservation Groups also claim that the EA’s analysis of shale gas development’s potential cumulative impacts omits reasonably foreseeable impacts on a variety of resources. 171. In considering cumulative impacts, CEQ advises that an agency first identify the significant cumulative effects associated with a proposed action. 223 The agency should 219 Kleppe, 427 U.S. at 413. 220 CEQ, Considering Cumulative Effects Under the National Environmental Policy Act at 8 (January 1997) (1997 CEQ Cumulative Effects Guidance), http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/G-CEQConsidCumulEffects.pdf. 221 Natural Res. Def. Council, Inc. v. Callaway, 524 F.2d at 88. 222 See CEQ, Memorandum on Guidance on Consideration of Past Actions in Cumulative Effects Analysis at 2-3 (June 24, 2005) (2005 CEQ Guidance), http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/G-CEQPastActsCumulEffects.pdf. 223 1997 CEQ Cumulative Effects Guidance at 11. Docket Nos. CP15-115-000 and CP15-115-001 - 65 - then establish the geographic scope for analysis. 224 Next, the agency should establish the time frame for analysis, equal to the timespan of a proposed project’s direct and indirect impacts. 225 Finally, the agency should identify other actions that potentially affect the same resources, ecosystems, and human communities that are affected by the proposed action. 226 As noted above, CEQ advises that an agency should relate the scope of its analysis to the magnitude of the environmental impacts of the proposed action. 227 172. The cumulative effects analysis in the EA comports with CEQ guidance. 228 The EA acknowledged that the Northern Access 2016 Project’s temporary and permanent impacts have the potential to cumulatively affect geology and soils; water resources; vegetation, fisheries, and wildlife; land use and visual resources; socioeconomics; cultural resources; air quality; noise; and climate change. 229 The EA fully explained that the chosen geographic scopes of the cumulative impact analysis were informed by several factors: the EA’s analysis of the project’s direct and indirect impacts had concluded that they would not be significant, the project’s impacts would almost all be contained within or be adjacent to the temporary construction right-of-way and alternative temporary workspaces; project-disturbed ecosystems would be restored or would otherwise recover; the mainline pipeline and Wheatfield Dehydration Facility would be co-located with existing facilities; and National Fuel would implement mitigation measures described in 224 Id. 225 Id. 226 Id. 227 See 2005 CEQ Guidance at 2-3, n.89, which notes that agencies have substantial discretion in determining the appropriate level of their cumulative impact assessments and that agencies should relate the scope of their analyses to the magnitude of the environmental impacts of the proposed action. Further, the Supreme Court held that determining the extent and effect of cumulative impacts, “and particularly identification of the geographic area within which they occur, is a task assigned to the special competency of the agenc[y],” and is overturned only if arbitrary and capricious. See Kleppe, 427 U.S. at 414-15. 228 See EA at 139-141. We also note that the 1997 CEQ Cumulative Effects Guidance states that the “applicable geographic scope needs to be defined case by case.” 1997 CEQ Cumulative Effects Guidance at 15. 229 EA at 139, 141. Docket Nos. CP15-115-000 and CP15-115-001 - 66 - its own plans and in the EA’s recommendations. 230 The chosen geographic scopes of analysis range from the project’s direct footprint for impacts on geologic and soil resources to four project-crossed watershed subbasins for impacts on water resources. 231 The EA identifies 75 actions affecting resources within these geographic areas in addition to the oil and natural gas wells and gathering lines that are “present throughout the region.” 232 173. The Conservation Groups object to the use of a 0.5-mile geographic scope for potential cumulative impacts to vegetation, wildlife, and land use. The groups assert that a 0.5-mile geographic scope conflicts with guidance from the CEQ and EPA stating that an agency’s cumulative impact analysis should use broader geographic boundaries like human communities, landscapes, watersheds, airsheds, and natural ecological boundaries. 233 The EA’s introduction misstates the geographic scope as 0.5 mile. The EA actually uses the watershed subbasin to analyze potential cumulative impacts to vegetation, fisheries, and wildlife species because these resources can be specialized within a watershed. 234 The USGS estimates the smallest of these subbasins to have a surface area of 560 square miles. 235 The EA uses a 5-mile area to analyze potential cumulative impacts to threatened and endangered species, explaining that this smaller 230 Conservation Groups Comments on the EA at 38-39. 231 EA at 141, 142, 143. The USGS estimates the surface area of these four “Hydrologic Unit Code 8” subbasins to total 4,667 square miles: 799 for Niagara, 717 for Buffalo-Eighteenmile, 560 for Cattaraugus, and 2591 for Upper Allegheny. See USGS, Watershed Boundary Dataset (last visited Dec. 8, 2016), http://water.usgs.gov/GIS/wbd_huc8.pdf. The EA’s other choices of geographic scope include: watershed subbasin for vegetation, wildlife, and land use; 5 miles for threatened and endangered species; affected counties for socioeconomic conditions; 0.25 mile for short-term air impacts; 31 miles for long-term air impacts; 0.25 mile for short-term noise impacts; and 1 mile for long-term noise impacts. EA at 141. 232 EA at 141; id. app. G, tbls.G-1, G-2 (identifying existing and future actions considered for potential cumulative impacts). 233 Conservation Groups Comments on the EA at 38-39 (citing CEQ, Considering Cumulative Effects under the NEPA at 12 (1997), EPA, Consideration of Cumulative Impacts in EPA Review of NEPA Documents at 8 (1999)). 234 EA at 146. 235 Supra note 202. Docket Nos. CP15-115-000 and CP15-115-001 - 67 - area reflects the localized nature of impacts, particularly for less mobile species. 236 The EA emphasizes that the project’s own impacts on vegetation, wildlife, and land use will be reduced through co-location with existing facilities, post-construction revegetation and restoration, and limited right-of-way maintenance. 237 The EA appropriately related the geographic scopes of analysis to the limited magnitude of the proposed action’s environmental impacts. The Conservation Groups offer no rationale that would delineate a broader geographic scope. 174. Also addressing vegetation, EPA claims that the EA should include a table detailing the total loss of trees from forest edges and forest interior resulting from pipelines within the affected counties. The EA notes that the project will permanently disturb 338.7 acres of forested lands and acknowledges that all projects constructed in the same general location and timeframe could result in additional habitat fragmentation where vegetation is modified from forest to scrub-shrub or herbaceous classes. 238 Though the precise impacts on vegetation from most of the 77 identified other actions within the geographic area cannot be known, the EA does quantify the reasonably foreseeable acreage of forested lands disturbed by ten other Commission-jurisdictional projects, 239 equal to 1109 combined acres (of which 233 were or will be permanently disturbed). Added to the Northern Access 2016 Project, the total acreage of permanently disturbed forested lands will be 561.7 acres. 175. Regarding land use, recreation, special interest areas, and visual resources, the Conservation Groups argue that the 10-mile geographic scope is too narrow. The groups claim that because National Fuel’s parent company identified Seneca Resources’ Western Development Area as the source of supply for the Northern Access 2016 Project, and because Seneca Resources will expand its shale gas development activities within its Western Development Area over time, the EA should have analyzed the cumulative impact on state and federal public lands, including the Allegheny National forest and Pennsylvania State Forest Lands, that are in “very close proximity” to the Northern Access 2016 Project and expanding shale gas development. 176. The Conservation Groups do not specify how “very close proximity” should differ from the EA’s 10-mile area and they do not specify the distances from the project to any 236 EA at 146. 237 EA at 147 (vegetation), 149 (wildlife), 151 (land use). 238 EA at 147. 239 EA at 147. Docket Nos. CP15-115-000 and CP15-115-001 - 68 - public lands. As we concluded in the discussion of indirect impacts above, the groups’ purported evidence of Seneca Resources’ future development does not provide enough detail to make the potential impacts from such development reasonably foreseeable and does not alter the geographic scope for the EA’s cumulative impact analysis for land use, recreation, special interest areas, and visual resources. 177. The Conservation Groups also assert that the EA fails to independently analyze the potential cumulative impact because the EA states that the impacts of the project and other actions will be reduced or eliminated through mitigation measures required under other federal and state permits. This assumption influences the EA’s conclusions about cumulative impacts on wetlands, surface waters, vegetation, water resources, fisheries and aquatic resources, and special status species. 240 The groups liken the EA’s analysis to those invalidated in Idaho v. Interstate Commerce Commission, 241 Calvert Cliffs Coordinating Committee v. U.S. Atomic Energy Commission, 242 and Wildearth Guardians v. U.S. office of Surface Mining, Reclamation and Enforcement. 243 178. The EA does not defer our NEPA responsibilities to other agencies; rather it explains that one factor in the EA’s cumulative impact conclusion for each affected resource is the anticipated compliance of the Northern Access 2016 Project and other actions with mitigation required by the Commission and other agencies under applicable laws. This assumption is reasonable. The Commission is not abdicating its responsibility nor are we deferring our analysis; rather, we are looking at the potential cumulative impacts in context. The EA quantifies other action’s potential cumulative impacts where practical, 244 and otherwise qualitatively describes those impacts, as CEQ recommends. The EA anticipates compliance with other agencies’ required measures as part of a complete picture both of the generally-described potential cumulative impacts and the generally-described mitigation of those impacts. By contrast, the Conservation Groups’ 240 EA at 145 (wetlands), 146 (surface waters), 147-148 (vegetation), 148 (fisheries and aquatic resources), 150 (special status species). 241 35 F.3d 585, 595 (D.C. Cir. 1994). 242 449 F.2d 1109, 1123 (D.C. Cir. 1971). 243 104 F. Supp. 3d 1208, 1227-28 (D. Colo. 2015). 244 For example, the EA identifies all vegetation losses from ten NGAjurisdictional projects. EA at 147. Docket Nos. CP15-115-000 and CP15-115-001 - 69 - cited cases all show federal agencies abdicating their NEPA responsibilities to defer to the scrutiny of other agencies. 245 179. At the core of the Conservation Groups’ objections to the EA’s cumulative impact analysis is the groups’ concern about natural gas development throughout the Marcellus Shale region. The Conservation Groups claim that available studies identify the “substantial impact” that past, present, and future shale gas drilling activities pose throughout the Marcellus and Utica shale regions, and that the Commission must take a hard look at these impacts on a much broader scale as part of the cumulative impact analysis. 246 180. There is a geographic limit to the scope of a cumulative impacts analysis. Courts have held that a meaningful cumulative impacts analysis must identify five things: “(1) the area in which the effects of the proposed project will be felt; (2) the impacts that are expected in that area from the proposed project; (3) other actions-past, present, and proposed, and reasonably foreseeable-that have had or are expected to have impacts in the same area; (4) the impacts or expected impacts from these other actions; and (5) the 245 Contra Idaho v. Interstate Commerce Comm’n, 35 F.3d 585, 589-590 (D.C. Cir. 1994) (Interstate Commerce Commission’s finding of no significant impact was unsupported by independent investigation of impact to wetlands, surface waters, or protected species, relying instead on requirements that applicant later consult with other agencies to determine potential impacts and obtain permits); Calvert Cliffs Coordinating Committee, Inc. v. U.S. Atomic Energy Comm’n, 449 F.2d 1109, 1122-27 (Atomic Energy Commission’s regulation prohibited agency’s consideration of problems of water quality, deferring instead to states’ analyses for water quality certifications); Wildearth Guardians v. US Office of Surface Mining, Reclamation and Enforcement, 104 F. Supp. 3d 1208, 1225-1226 (D. Colo. 2015) (Office of Surface Mining’s findings of no significant impact in a pair of four-page EAs were unsupported by independent investigation, relying instead on outdated studies and on the proposed decision and findings of state’s mining agency). 246 Conservation Groups Comments on the EA at 42-55 (citing Milheim et al., U.S. Geological Survey, Landscape Consequences of Natural Gas Extraction in Cameron, Clarion, Elk, Forest, Jefferson, McKean, Potter, and Warren Counties, Pennsylvania, 2004-2010, Open-File Report 2014-1152 (2014) (2014 USGS Report); Brittingham, et. al., Ecological Risks of Shale Oil and Gas Development to Wildlife, Aquatic Resources, and Their Habitats, 48 ENVTL. SCIENCE & TECHNOLOGY 11034 (Oct. 7, 2014) (published online on Sept. 4, 2014) (2014 Brittingham study); PA Dep’t of Conservation and Natural Res., 2015 Draft State Forest Management Plan (Sept. 2015); U.S. Forest Serv., Allegheny National Forest Roads Analysis Report (2003). Docket Nos. CP15-115-000 and CP15-115-001 - 70 - overall impact that can be expected if the individual impacts are allowed to accumulate.” 247 As explained above, we affirm the EA’s chosen geographic boundaries for each affected resource. The EA appropriately quantifies the potential for cumulative impacts to the extent practicable, and otherwise describes it qualitatively. 248 The EA appropriately explains that actions outside the chosen geographic scope of analysis are in most cases not assessed because their impacts would tend to be localized and not contribute significantly to the impacts of the proposed project. 249 We believe the EA’s analysis is consistent with the CEQ guidance and case law. 250 181. The impacts from natural gas development on a broader scale are appropriately omitted from the EA. Given the large geographic scope of the Marcellus and Utica shale resources, the magnitude of the analysis requested by the Conservation Groups bears no relationship to the limited magnitude of the Northern Access 2016 Project’s 27.8 miles of pipeline in McKean County, Pennsylvania, of which 14 miles are co-located with existing right-of-way. 251 The remaining 71 miles of pipeline, both compressor stations, and the dehydration facility sit in New York where shale gas development is prohibited. Moreover, even if the Commission were to vastly expand the geographic scope of the cumulative effects analysis, the impacts from such development are not reasonably foreseeable. 252 Accordingly, the EA appropriately excluded broader shale gas drilling activities in the Marcellus and Utica shale formations. 247 Sierra Club v. FERC, 827 F.3d 36, 49 (D.C. Cir. 2016) (quoting Taxpayers of Michigan Against Casinos v. Norton, 433 F.3d. 852, 864 (D.C. Cir. 2006)) (emphasis added). 248 EA at 140. 249 EA at 140. 250 See 1997 CEQ Guidance at 15. 251 EA at 7 tbl.A.4.a-1. 252 The studies cited by the Conservation Groups, supra note 242, are not specific enough to meaningfully inform the Commission’s decision making. The cited 2014 USGS report provides only a retrospective analysis using aerial images to detect land use and land cover changes from natural gas development between 2004 and 2010. The 2014 Brittingham study, as well as the 2015 plan from Pennsylvania’s natural resources agency and the 2003 report from the U.S. Forest Service, offer only general conclusions about the potential qualitative impacts on terrestrial and aquatic ecosystems from shale development. They do not quantify specific impacts, much less describe or quantify the (continued...) Docket Nos. CP15-115-000 and CP15-115-001 - 71 - 182. In our view, the Conservation Groups’ arguments regarding the geographic scope of our cumulative impacts analysis are based on their erroneous claim, discussed above, that the Commission must conduct a regional programmatic NEPA review of natural gas development and production in the Marcellus and Utica shale formations, an area that covers potentially thousands of square miles. We decline to do so. As the Commission has previously explained, there is no Commission program or policy to promote additional natural gas development and production in shale formations. 183. The EA did identify that oil and natural gas wells and gathering lines are present throughout the region and noted that the EA would treat as one project all the oil and natural gas wells and gathering lines present within McKean County, where the project’s receipt interconnection is located. 253 The EA analyzed, to the extent practical, the potential cumulative impacts from natural gas development within the selected geographic boundaries for geologic and soil resources, water resources, vegetation/fisheries/wildlife, threatened and endangered species, land use and visual resources, socioeconomics, air quality, climate change, and noise. For example, within the EA’s 0.25-mile boundary for affected geologic and soil resources, the EA identified 66 active oil and gas wells, 34 plugged and abandoned wells, 13 wells of unknown status, and 6 wells proposed but never drilled. 254 Where possible, the EA quantified productionrelated impacts. For example, the EA used figures from the USGS that each well pad and its associated infrastructure uses 9 acres of land and indirectly affects 21 acres of land. The EA calculated that the development of the 118 wells currently drilled or proposed within 0.25 mile of the project would use 1,062 acres of land and indirectly affect 2,478 acres of land, presumed to be forested. 255 184. As noted above, upstream and downstream impacts of the type described by commenters do not meet the CEQ definition of either indirect or cumulative impacts. Therefore, they are not mandated as part of the Commission’s NEPA review. However, to provide the public additional information and to inform our public convenience and necessity determination under section 7(e) of the Natural Gas Act, 256 Commission staff, subset of impacts that potentially overlap with the impacts of the Northern Access 2016 Project. 253 EA at 141; id. app. G at G-5. 254 EA at 142. 255 EA at 151. 256 15 U.S.C. § 717f(e) (2012). Docket Nos. CP15-115-000 and CP15-115-001 - 72 - after reviewing publicly available DOE and EPA methodologies, has prepared the following analyses regarding the potential impacts associated with unconventional gas production and downstream combustion of natural gas. As summarized below, these analyses provide only an upper-bound estimate of upstream and downstream effects. In addition, these estimates are generic in nature because no specific end uses have been identified and reflect a significant amount of uncertainty. 185. With respect to upstream impacts, Commission staff estimated the impacts associated with the production wells that would be required to provide 100 percent of the volume of natural gas to be transported by the Northern Access 2016 Project, on an annual basis for GHG, and for the life of the project for land-use and water use within the Marcellus shale basin. 257 According to a 2016 study by the DOE and the National Energy Technology Laboratory (NETL), approximately 1.48 acres of land is required for each natural gas well pad and associated infrastructure (road infrastructure, water impoundments, and pipelines). 258 Based upon the project capacity and the expected estimated ultimate recovery of Marcellus shale wells, 259 between 1,100 and 2,100 wells would be required to provide the gas over the estimated 30-year lifespan of the project. Therefore, on a normalized basis over the life of the project, 260 these assumptions lead us to estimate an upper-bound between 52 and 100 additional acres per year may be impacted for well drilling. 261 This estimate of the number of wells is imprecise and subject to a significant amount of uncertainty. 257 Staff assumed a 30-year life for the project. 258 Life Cycle Analysis of Natural Gas Extraction and Power Generation, DOE/NETL-2015/1714 at 22 tbl.3-6 (Aug. 30, 2016) (2016 Life Cycle Analysis). 259 John Staub, Energy Information Administration, “The Growth of U.S. Natural Gas: An Uncertain Outlook for U.S. and World Supply,” Presentation at 2015 EIA Energy Conference, Washington, D.C. (June 15, 2015), http://www.eia.gov/conference/ 2015/pdf/presentations/staub.pdf, and DOE, National Energy Technology Laboratory, Environmental Impacts of Unconventional Natural Gas Development and Production DOE/NETL-2014/1651 (May 29, 2014). 260 Normalized yearly impacts are estimated based on the overall impacts for the life of the project averaged on a per year basis. 261 2016 Life Cycle Analysis at 24 tbl.3-8. The 2016 Life Cycle Analysis estimates that within the Appalachian Shale region, the affected acreage would be composed of 72.3 percent forested land, 22.4 percent agricultural land, and 5.3 percent grass or open lands. Docket Nos. CP15-115-000 and CP15-115-001 - 73 - 186. We also estimated the amount of water required for the drilling and development of these wells over the 30-year period using the same assumptions. In a separate 2014 study, DOE and NETL estimated that an average Marcellus shale well requires between 3.88 and 5.69 million gallons of water for drilling and well development, depending on whether the producer uses a recycling process in the well development. 262 Therefore, the production of wells necessary to supply the project could require as much as 140 to 400 million gallons of water per year on a normalized basis over the 30 year life of the project. 187. Regarding climate change, the Conservation Groups object to the EA’s comparison of potential cumulative GHG emissions (i.e., from the project and from the identified other actions) to the total annual GHG emissions in Pennsylvania and New York as a basis to conclude that GHG emissions would be minor. The groups note that CEQ guidance about greenhouse gas emissions explains that a comparison to global emissions is an inappropriate basis for (a) deciding whether or to what extent to consider climate change impacts under NEPA or (b) characterizing the potential impacts of the proposed action, reasonable alternatives, and mitigation. The groups also refute the Commission’s statement that no standard methodology exists to determine how a project’s contribution to GHG emissions would translate into physical effects on the environment, given that CEQ’s guidance states that “[q]uantification tools are widely available and are already in broad use.” 263 188. The CEQ guidance warns that agencies should not limit themselves to calculating a proposed action’s emissions as a percentage of sector, nationwide, or global emissions. The EA was not limited in this way. The CEQ guidance does not prohibit a comparison to statewide emissions as a frame of reference to better understand the magnitude of GHG emissions. The EA correctly concludes that no standard methodology exists to determine how a project’s contribution to GHG emissions would translate into physical effects on the environment. Without an accepted methodology, the Commission cannot make a finding whether a particular quantity of GHG emissions poses a significant impact to the environment, whether directly or cumulatively with other sources. 189. The EA does not include upstream and downstream GHG emissions; however, Commission staff has conservatively estimated upper-bound annual upstream GHG emissions as: 410,000 tpy CO2e from extraction, 790,000 tpy CO2e from processing, and 262 DOE, NETL, Environmental Impacts of Unconventional Natural Gas Development and Production, DOE/NETL-2014/1651 at 76, ex.4-1 (May 29, 2014). 263 at 12). Conservation Groups Comments on EA at 57 (quoting CEQ’s GHG guidance Docket Nos. CP15-115-000 and CP15-115-001 - 74 - 250,000 tpy CO2e from the non-project pipelines (both upstream and downstream to the delivery point in Chippawa). Commission staff has conservatively estimated upperbound annual downstream emissions as 9,200,000 tpy CO2e from end-use combustion. 264 190. Again, this is an upper-bound estimate that involves a significant amount of uncertainty. This is especially true for downstream end-use combustion because some of the gas may displace other fuels, which could actually lower total CO2e emissions. It may also displace gas that otherwise would be transported via different means, resulting in no change in CO2e emissions. This estimate also assumes the maximum capacity is transported 365 days per year, which is rarely the case because many projects are designed for peak use. Therefore, it is unlikely that this total amount of GHG emissions would occur; and emissions are likely to be significantly lower than the above estimate. 191. Oil Change International asserts that the effects of natural gas on climate change are equal to or greater than coal if the comparison uses the most recent factors for methane’s global warming potential from the fifth report of the Intergovernmental Panel on Climate Change and uses gas leakage rates of up to 5.4 percent for conventional wells and 12 percent for shale wells. 265 The coalition notes that the fifth report uses a 20-year impact of methane equal to 86 times that of CO2 and a 100-year impact equal to 36 times that of CO2. The Commission instead relied on established methodologies used by the EPA and DOE. 192. We find that the EA appropriately evaluates the potential cumulative impacts associated with the project and other past, present, and reasonably foreseeable future projects, including natural gas development, and agree with its conclusions. 264 The upstream GHG emissions were estimated using methods in NETL’s 2016 Life Cycle Analysis. Generally, Commission staff used the average leak and emission rates identified in the NETL analysis for each segment of extraction, processing, and transport. The method is outlined in Section 2 of the NETL report, and the background data used for the model is outlined in Section 3.1. Staff used the results identified in Figures 4.3, 4.4, and 4.5 to look at each segment and grossly estimate GHG emission. To be conservative, staff did not account for the new New Source Performance Standards for oil and gas, or other GHG mitigation. See Oil and Natural Gas Sector: Emissions Standards for New, Reconstructed, and Modified Sources, 81 Fed. Reg. 35,824 (June 3, 2016) (altering 40 C.F.R. pt. 60, subpts. OOOO and OOOOa). Additionally, staff made a conservative estimate of the length of non-jurisdictional pipeline prior to the gas reaching project components as well as the length of downstream pipeline to the delivery point in Chippawa. 265 Oil Change International August 8, 2016 Comments on the EA at 22. Docket Nos. CP15-115-000 and CP15-115-001 12. - 75 - Other Issues 193. A commenter states that the project, specifically the Wheatfield Dehydration Facility and associated piping, is within the Niagara River Greenway. The Niagara River Greenway Plan notes that the greenway was mapped by jurisdictional boundaries (i.e., town limits) and not by sensitive resources or stretches of river. 266 Thus the proposed facility falls within the mapped greenway area. The plan also notes that the Niagara River Greenway Commission “recognizes that efforts and resources should be focused on the Niagara River and its shoreline.” The Wheatfield Dehydration Facility would not impact the river or shoreline, as it is located in a previously disturbed area separated from the river by other development including industrial facilities. Therefore, we conclude that the project will not impact the greenway. 194. Commenters, including the Town of Pendleton, state that local land use laws do not allow for development of the Pendleton Compressor Station at the proposed location. We note that any state or local permits issued with respect to the jurisdictional facilities authorized herein must be consistent with the conditions of this certificate. We encourage cooperation between interstate pipelines and local authorities. However, this does not mean that state and local agencies, through application of state or local laws, may prohibit or unreasonably delay the construction or operation of facilities approved by this Commission. 267 195. One commenter questions the effectiveness of having a National Fuel-employed environmental inspector monitoring compliance with permit conditions. As noted in the EA, a Commission-directed environmental compliance monitor will also oversee 266 Niagara River Greenway Commission, Niagara River Greenway Plan and Final Environmental Impact Statement at 7-9 (Apr. 4 2007), http://www.niagaragreenway .org/sites/all/themes/nrgc/FINAL%20REPORT.pdf. The plan also notes that the Niagara River Greenway Commission “recognizes that efforts and resources should be focused on the Niagara River and its shoreline.” Id. at 7. 267 See 15 U.S.C. § 717r(d) (2012) (state or federal agency’s failure to act on a permit considered to be inconsistent with Federal law); see also Schneidewind v. ANR Pipeline Co., 485 U.S. 293, 310 (1988) (state regulation that interferes with FERC’s regulatory authority over the transportation of natural gas is preempted) and Dominion Transmission, Inc. v. Summers, 723 F.3d 238, 245 (D.C. Cir. 2013) (noting that state and local regulation is preempted by the NGA to the extent it conflicts with federal regulation, or would delay the construction and operation of facilities approved by the Commission). Docket Nos. CP15-115-000 and CP15-115-001 - 76 - National Fuel’s adherence to environmental commitments and regulations. 268 If this monitor identifies issues of non-compliance, the monitor can report the issues directly to the Commission staff environmental project manager. Commission environmental staff will address any non-compliance, including by developing additional protective measures. Moreover, the costs of delays during construction that come from permit noncompliance serve as suitable incentives for companies to strictly adhere to regulations and permit stipulations. 196. The FWS recommends that an environmental monitor be on-site during in-stream construction. National Fuel has committed to having environmental inspectors on-site during all construction, including during in-stream activities. Additional monitors from either the Commission staff or regulatory agencies may also be present during those activities, offering sufficient oversight during in-stream construction. IV. Conclusion 197. Based on the information and analysis in the EA and in this order, we conclude that if constructed and operated in accordance with National Fuel’s and Empire’s application and supplements, and in compliance with the environmental conditions in Appendix B of this order, our approval of this proposal will not constitute a major federal action significantly affecting the quality of the human environment. 198. The Commission on its own motion received and made part of the record in this proceeding all evidence, including the application(s), as supplemented, and exhibits thereto, submitted in support of the authorizations sought herein, and upon consideration of the record, The Commission orders: (A) A certificate of public convenience and necessity is issued to National Fuel Gas Supply Corporation authorizing it to construct and operate the Northern Access 2016 Project, as described and conditioned herein, and as more fully described in its application. (B) A certificate of public convenience and necessity is issued to Empire Pipeline, Incorporated, authorizing it to construct and operate the Northern Access 2016 Project, as described and conditioned herein, and as more fully described in its application. 268 EA at 19. Docket Nos. CP15-115-000 and CP15-115-001 - 77 - (C) The certificate authority issued in Ordering Paragraphs (A) and (B) are conditioned on National Fuel’s and Empire’s: (1) completing the authorized construction of the proposed facilities and making them available for service within two years of the date of this order, pursuant to section 157.20(b) of the Commission’s regulations; (2) compliance with all applicable Commission regulations including, but not limited to, Parts 154, 157, and 284, and paragraphs (a), (c), (e), and (f) of section 157.20 of the Commission’s regulations; (3) compliance with the environmental conditions in Appendix B to this order; and (4) executing contracts, prior to the commencement of construction, for the firm service in accordance with the volumes and the terms of service reflected in its precedent agreements. (D) National Fuel and Empire shall notify the Commission’s environmental staff by telephone, e-mail, and/or facsimile of any environmental noncompliance identified by other federal, state, or local agencies on the same day that such agency notifies National Fuel or Empire. National Fuel and Empire shall file written confirmation of such notification with the Secretary of the Commission within 24 hours. (E) Empire’s incremental recourse rate for transportation service under Rate Schedule FT – Original Empire Pipeline is approved. (F) Empire’s request for a pre-determination supporting rolled-in rate treatment for the costs of the pin its next general NGA section 4 rate proceeding is denied, as described above. (G) National Fuel's request for waiver of its GT&C section 31.1 is denied, as discussed above. (H) approved. Empire’s request to charge an initial Pendleton Compressor fuel factor is (I) National Fuel and Empire shall file revised actual tariff records no earlier than 60 days and no later than 30 days, prior to the date the project facilities go into service. (J) National Fuel and Empire shall keep separate books and accounts of costs attributable to the proposed incremental services, as described above. Docket Nos. CP15-115-000 and CP15-115-001 - 78 - (K) National Fuel is granted permission and approval under section 7(b) of the NGA to abandon the facilities described in this order. (L) Empire is granted permission and approval under section 7(b) of the NGA to abandon the facilities described in this order. (M) National Fuel and Empire must notify the Commission within 10 days of the abandonment of the facilities discussed in Ordering Paragraphs K and L. (N) The untimely motions to intervene are granted. (O) National Fuel’s and Empire’s motion to answer protests is rejected. By the Commission. Commissioner Bay’s separate statement is attached. (SEAL) Kimberly D. Bose, Secretary. Docket Nos. CP15-115-000 and CP15-115-001 Appendix A – Timely Intervenors Responding to the March 27, 2015 Notice of Application Allegheny Defense Project Anadarko Energy Services Company Edward J. Burger, Jr. Jean Burger Chevron USA Inc. Barbara Ciepiela ConocoPhillips Company Consolidated Edison Company of New York, Inc. Cross Timbers Energy Services, Inc. Direct Energy Business Marketing, LLC Gary Gilman Barabara Glavin National Grid Gas Delivery Companies New York State Department of Environmental Conservation New York State Electric & Gas Corporation NiSource Distribution Companies: Columbia Gas of Pennsylvania Bay State Gas Company d/b/a Columbia Gas of Massachusetts NJR Energy Services Company John C. Partsch Eugene Parzych Town of Pendleton, New York Pennsylvania Alliance for Clean Water and Air Range Resources-Appalachia, LLC Rochester Gas and Electric Corporation Seneca Resources Corporation Shell Energy North America (US), L.P. SWEPI LP Responding to the November 11, 2015 Notice of Amendment to Application Myles S. Barraclough Jason Brosius Mary Bryant - 79 - Docket Nos. CP15-115-000 and CP15-115-001 Amy L. Bush Donna Hahn Paula J. Hargreaves Michael Kubiak Kimberly Lemieux Victor Lemieux Joel Maerten Roy A. Mura National Fuel Gas Distribution Corporation Sam and Lynn Pinto Kristen R. Sidebottom Karen Slote Ann Marie Paglione Angela Passalacqua Gino Passalacqua Kim Zugelder - 80 - Docket Nos. CP15-115-000 and CP15-115-001 - 81 - Appendix B – Environmental Conditions 1. 2. National Fuel Gas Supply Corporation (National) and Empire Pipeline, Inc. (Empire) (collectively referred to as National Fuel) shall follow the construction procedures and mitigation measures described in its applications and supplements (including responses to staff data requests) and as identified in the EA, unless modified by the Order. National Fuel must: a. request any modification to these procedures, measures, or conditions in a filing with the Secretary of the Commission (Secretary); b. justify each modification relative to site-specific conditions; c. explain how that modification provides an equal or greater level of environmental protection than the original measure; and d. receive approval in writing from the Director of the Office of Energy Projects (OEP) before using that modification. The Director of OEP has delegated authority to take whatever steps are necessary to ensure the protection of all environmental resources during construction and operation of the Project. This authority shall allow: a. the modification of conditions of the Order; and b. the design and implementation of any additional measures deemed necessary (including stop-work authority) to assure continued compliance with the intent of the environmental conditions as well as the avoidance or mitigation of adverse environmental impact resulting from project construction and operation. 3. Prior to any construction, National Fuel shall file an affirmative statement with the Secretary, certified by a senior company official, that all company personnel, environmental inspectors (EI), and contractor personnel will be informed of the EI’s authority and have been or will be trained on the implementation of the environmental mitigation measures appropriate to their jobs before becoming involved with construction and restoration activities. 4. The authorized facility location(s) shall be as shown in the EA, as supplemented by filed alignment sheets. As soon as they are available, and before the start of construction, National Fuel shall file with the Secretary any revised detailed survey alignment maps/sheets at a scale not smaller than 1:6,000 with station positions for all facilities approved by the Order. All requests for modifications of environmental conditions of the Order or site-specific clearances must be written and must reference locations designated on these alignment maps/sheets. Docket Nos. CP15-115-000 and CP15-115-001 - 82 - National Fuel’s exercise of eminent domain authority granted under Natural Gas Act Section 7(h) in any condemnation proceedings related to the Order must be consistent with these authorized facilities and locations. National Fuel’s right of eminent domain granted under Natural Gas Act Section 7(h) does not authorize it to increase the size of its natural gas pipeline or facilities to accommodate future needs or to acquire a right-of-way for a pipeline to transport a commodity other than natural gas. 5. National Fuel shall file with the Secretary detailed alignment maps/sheets and aerial photographs at a scale not smaller than 1:6,000 identifying all route realignments or facility relocations, and staging areas, pipe storage yards, new access roads, and other areas that would be used or disturbed and have not been previously identified in filings with the Secretary. Approval for each of these areas must be explicitly requested in writing. For each area, the request must include a description of the existing land use/cover type, documentation of landowner approval, whether any cultural resources or federally listed threatened or endangered species would be affected, and whether any other environmentally sensitive areas are within or abutting the area. All areas shall be clearly identified on the maps/sheets/aerial photographs. Each area must be approved in writing by the Director of OEP before construction in or near that area. This requirement does not apply to extra workspace allowed by the National Fuel’s Erosion and Sediment Control and Agricultural Mitigation Plan and/or minor field realignments per landowner needs and requirements which do not affect other landowners or sensitive environmental areas such as wetlands. Examples of alterations requiring approval include all route realignments and facility location changes resulting from: a. implementation of cultural resources mitigation measures; b. implementation of endangered, threatened, or special concern species mitigation measures; c. recommendations by state regulatory authorities; and d. agreements with individual landowners that affect other landowners or could affect sensitive environmental areas. Docket Nos. CP15-115-000 and CP15-115-001 6. Within 60 days of the acceptance of the authorization and before construction begins, National Fuel shall file an Implementation Plan with the Secretary for review and written approval by the Director of OEP. National Fuel must file revisions to the plan as schedules change. The plan shall identify: a. how National Fuel will implement the construction procedures and mitigation measures described in its application and supplements (including responses to staff data requests), identified in the EA, and required by the Order; b. how National Fuel will incorporate these requirements into the contract bid documents, construction contracts (especially penalty clauses and specifications), and construction drawings so that the mitigation required at each site is clear to onsite construction and inspection personnel; c. the number of EIs assigned (per spread), and how the company will ensure that sufficient personnel are available to implement the environmental mitigation; d. company personnel, including EIs and contractors, who will receive copies of the appropriate material; e. the location and dates of the environmental compliance training and instructions National Fuel will give to all personnel involved with construction and restoration initial and refresher training as the Project progresses and personnel change. f. the company personnel (if known) and specific portion of National Fuel's organization having responsibility for compliance; g. the procedures (including use of contract penalties) National Fuel will follow if noncompliance occurs; and h. for each discrete facility, a Gantt or PERT chart (or similar project scheduling diagram), and dates for: (1) (2) (3) (4) 7. - 83 - the completion of all required surveys and reports; the environmental compliance training of onsite personnel; the start of construction; and the start and completion of restoration. National Fuel shall employ at least one EI per construction spread. The EI(s) shall be: Docket Nos. CP15-115-000 and CP15-115-001 8. - 84 - a. responsible for monitoring and ensuring compliance with all mitigation measures required by the Order and other grants, permits, certificates, or other authorizing documents; b. responsible for evaluating the construction contractor's implementation of the environmental mitigation measures required in the contract (see condition 6 above) and any other authorizing document; c. empowered to order correction of acts that violate the environmental conditions of the Order, and any other authorizing document; d. a full-time position, separate from all other activity inspectors; e. responsible for documenting compliance with the environmental conditions of the Order, as well as any environmental conditions/permit requirements imposed by other federal, state, or local agencies; and f. responsible for maintaining status reports. Beginning with the filing of its Implementation Plan, National Fuel shall file updated status reports with the Secretary on a weekly basis until all construction and restoration activities are complete. On request, these status reports will also be provided to other federal and state agencies with permitting responsibilities. Status reports shall include: a. an update on National Fuel’s efforts to obtain the necessary federal authorizations; b. the construction status of the Project, work planned for the following reporting period, and any schedule changes for stream crossings or work in other environmentally-sensitive areas; c. a listing of all problems encountered and each instance of noncompliance observed by the EI(s) during the reporting period (both for the conditions imposed by the Commission and any environmental conditions/permit requirements imposed by other federal, state, or local agencies); d. a description of the corrective actions implemented in response to all instances of noncompliance, and their cost; e. the effectiveness of all corrective actions implemented; f. a description of any landowner/resident complaints which may relate to compliance with the requirements of the Order, and the measures taken to satisfy their concerns; and Docket Nos. CP15-115-000 and CP15-115-001 g. 9. - 85 - copies of any correspondence received by National Fuel from other federal, state, or local permitting agencies concerning instances of noncompliance, and National Fuel’s response. National Fuel shall develop and implement environmental complaint resolution procedures. The procedures shall provide landowners with clear and simple directions for identifying and resolving their environmental mitigation problems/concerns during construction of the project and restoration of the rightof-way. Prior to construction, National Fuel shall mail the complaint procedures to each landowner whose property would be crossed by the project. a. In its letter to affected landowners, National Fuel shall: (1) (2) (3) b. provide a local contact that the landowners should call first with their concerns; the letter should indicate how soon a landowner should expect a response; instruct the landowners that if they are not satisfied with the response, they should call National Fuel's Hotline; the letter should indicate how soon to expect a response; and instruct the landowners that if they are still not satisfied with the response from National Fuel's Hotline, they should contact the Commission’s Landowner Helpline at 877-337-2237 or at LandownerHelp@ferc.gov. In addition, National Fuel shall include in its weekly status report a copy of a table that contains the following information for each problem/concern: (1) (2) (3) (4) the identity of the caller and date of the call; the location by milepost and identification number from the authorized alignment sheet(s) of the affected property; a description of the problem/concern; and an explanation of how and when the problem was resolved, will be resolved, or why it has not been resolved. 10. Prior to receiving written authorization from the Director of OEP to commence construction of any Project facilities, National Fuel shall file with the Secretary documentation that it has received all applicable authorizations required under federal law (or evidence of waiver thereof). 11. National Fuel must receive written authorization from the Director of OEP before placing the Project into service. Such authorization will only be granted following a determination that rehabilitation and restoration of the right-of-way and other areas affected by the Project are proceeding satisfactorily. Docket Nos. CP15-115-000 and CP15-115-001 12. - 86 - Within 30 days of placing the authorized facilities in service, National Fuel shall file an affirmative statement with the Secretary, certified by a senior company official: a. that the facilities have been constructed in compliance with all applicable conditions, and that continuing activities will be consistent with all applicable conditions; or b. identifying which of the conditions in the Order National Fuel has complied with or will comply with. This statement shall also identify any areas affected by the Project where compliance measures were not properly implemented, if not previously identified in filed status reports, and the reason for noncompliance. 13. Prior to construction, National Fuel shall file with the Secretary, for review and written approval by the Director of OEP, an analysis of the direct pipe drill method as an alternate method at the two road crossings and the Allegheny River crossing. 14. Prior to construction, National Fuel shall file with the Secretary, for review and written approval by the Director of OEP, a geotechnical exploration report that evaluates slope configurations and stability evaluations for the Pendleton Compressor Station and interconnect with Tennessee Gas Pipeline Company, L.L.C. 15. Prior to construction, National Fuel shall file with the Secretary, for review and written approval by the Director of OEP: a. a desktop evaluation utilizing topographic maps and LiDAR imagery to assess the degree of karst development, if any, along the EMP-03 pipeline alignment and the Wheatfield Dehydration Facility in Niagara County. The evaluation shall be followed by a site reconnaissance to field verify and map karst features identified; b. if necessary, conduct a geotechnical investigation that identifies areas along the EMP-03 pipeline and within the Wheatfield Dehydration Facility site; and c. if necessary, based on the results of a and b above, prepare a karst mitigation plan that includes the specific measures that will be implemented to avoid (minor adjustment of facilities) or mitigate (properly close or protect) karst features encountered during construction. At a minimum, the construction measures in this plan shall include: (1) stopping work in the area until a remedial assessment is carried out; Docket Nos. CP15-115-000 and CP15-115-001 (2) (3) (4) (5) - 87 - notifying the New York Geological Survey and FERC staff that karst features have been encountered; prohibiting construction equipment, vehicles, hazardous materials, chemicals fuels lubricating oils, and petroleum products from being parked, refueled, stored or serviced within a 100 foot radius of any karst feature; installing additional erosion control measures to prevent drainage toward any karst feature; and using a qualified geologist licensed in the state where the work is being performed to monitor excavation activities at high probability karst. 16. Within 30 days of placing the facilities in service, National Fuel shall file with the Secretary a report describing any complaints it received regarding well yield or water quality, the results of any water quality or yield testing that was performed, and how each complaint was resolved. 17. In the event of the failure of any waterbody horizontal directional drill, National Fuel shall file with the Secretary a site-specific open-cut or other crossing plan(s) for review and approval by the Director of OEP. National Fuel shall develop the plans in consultation with the U.S. Army Corps of Engineers and the U.S. Fish and Wildlife Service and the plans shall include scaled drawings identifying all areas that will be disturbed by construction and a description of the mitigation measures that will be implemented to minimize effects on water quality and in-stream resources. 18. Prior to construction, National Fuel shall file with the Secretary letters of concurrence from the U.S. Fish and Wildlife Service and the New York State Department of Environmental Conservation demonstrating that water withdrawal from Oil Creek and the Allegheny River is acceptable. 19. Prior to construction, National Fuel shall file with the Secretary, for review and written approval from the Director of the OEP, revised project alignment sheets to clarify that the additional temporary workspace proposed in wetlands at mileposts 24.8 and 76.7 and in waterbodies at mileposts 5.0, 9.9, and 24.9 have been removed or moved to where the additional temporary workspaces will be set back at least 10 feet from the water’s edge. 20. Prior to construction, National Fuel shall file with the Secretary, for review and written approval from the Director of OEP, a revised table B.2.c-2 that demonstrates the additional temporary workspaces will be properly set back from the feature; or National Fuel shall provide additional justification for the workspace locations. Docket Nos. CP15-115-000 and CP15-115-001 - 88 - 21. Prior to construction, National Fuel shall file with the Secretary, for review and written approval by the Director of OEP, a final invasive plant species plan developed through coordination with the New York State Department of Environmental Conservation and Pennsylvania Department of Conservation and Natural Resources identifying the practices that will be implemented during construction and restoration activities to prevent the introduction and spread of invasive species. 22. National Fuel shall not begin construction activities until: a. freshwater mussel surveys are complete for Dodge Creek and Ischua Creek for the clubshell and the rayed bean; b. National Fuel submits full survey reports to the U.S. Fish and Wildlife Service’s New York Field Office, the Pennsylvania Fish and Boat Commission, and the Secretary; c. the FERC staff completes Endangered Species Act Section 7 consultation with the U.S. Fish and Wildlife Service; and d. National Fuel has received written notification from the Director of OEP that construction or use of mitigation may begin. 23. Prior to construction in the Bear Creek State Forest, National Fuel shall file with the Secretary, for review and written approval by the Director of OEP, its final plan for construction across the state forest including any special mitigation measures, restoration measures, and any applicable agency correspondence. 24. Prior to construction, National Fuel shall file with the Secretary, for review and written approval of the Director of OEP, its final visual screening plan for the Pendleton Compressor Station. The plan shall, at a minimum, show the locations of facility components, roads, and parking areas, and include a description of the types and quantities of vegetation screening to be planted. The plan shall also describe how National Fuel’s building design is consistent with the existing landscape. 25. National Fuel shall not begin implementation of any treatment plans/measures (including archaeological data recovery); construction of facilities; or use of any staging, storage, or temporary work areas and new or to-be-improved access roads in areas not previously evaluated or where access was denied until: a. National Fuel files with the Secretary: (1) all cultural resources survey reports, including evaluation reports, avoidance plans, and treatment plans; Docket Nos. CP15-115-000 and CP15-115-001 (2) (3) b. - 89 - comments on survey reports, evaluation reports, avoidance plans, and treatment plans from the State Historic Preservation Office as well as any comments from federally recognized Indian tribes; comments from the Advisory Council on Historic Preservation if historic properties would be adversely affected; and The FERC staff reviews and the Director of OEP approves all cultural resources survey reports and plans, and notifies National Fuel in writing that treatment plans/measures may be implemented and/or construction may proceed. All material filed with the FERC that contains location, character, and ownership information about cultural resources must have the cover and any relevant pages therein clearly labeled in bold lettering: “CONTAINS PRIVILEGED INFORMATION – DO NOT RELEASE.” 26. Prior to construction of the Highway 16 horizontal directional drill, National Fuel shall file with the Secretary, for the review and written approval by the Director of OEP, an horizontal directional drill noise mitigation plan to reduce the projected noise level attributable to the drilling operations at the Highway 16 horizontal directional drill entry location. During operation of the horizontal directional drill, National Fuel shall implement the approved plan, monitor noise levels, include the noise level results in its weekly status reports, and make all reasonable efforts to restrict the noise attributable to the drilling operations to no more than a day-night sound level of 55 decibels on the A-weighted scale at the closest noise sensitive areas to the horizontal directional drill entry point. 27. National Fuel shall file with the Secretary, for review and approval of the Director of OEP, a noise survey no later than 60 days after placing the Pendleton Compressor Station, Porterville Compressor Station, Wheatfield Dehydration Facility, X-N Pressure Reduction Station, TGP 200 Interconnect Station, and Hinsdale Meter Station into service. If a full load condition noise survey is not possible, National Fuel shall provide an interim survey at the maximum possible power load and provide the full power load survey within 6 months. If the noise attributable to the operation of all of the equipment at any facility at interim or full power load conditions exceeds 55 decibels on the A-weighted scale day-night sound level at any nearby noise sensitive areas, National Fuel shall file a report on what changes are needed and shall install additional noise controls to meet the level within 1 year of the in-service date. National Fuel shall confirm compliance with the above requirement by filing a second noise survey with the Secretary no later than 60 days after it installs the additional noise controls. UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION National Fuel Gas Supply Corporation Empire Pipeline, Inc. Docket Nos. CP15-115-000 CP15-115-001 ORDER GRANTING ABANDONMENT AND ISSUING CERTIFICATES (Issued February 3, 2017) BAY, Commissioner, Separate Statement The shale revolution has upended U.S. energy markets. Only a decade ago, the United States was thought to be running out of oil and gas, and imports of both were growing. Today, we are the world’s leading producer of oil and gas, with new production coming from shale formations across the United States. 1 To serve the new production areas and to satisfy increasing demand, the interstate pipeline industry has built and is planning to build a large amount of infrastructure. In 2016, daily gas production in the United States stood at 72.4 billion cubic feet per day (Bcfd). 2 That same year, the Commission certificated 17.6 Bcfd of pipeline capacity. This infrastructure expansion, coupled with growing production, has resulted in declining natural gas prices and a significant reduction in basis differentials – the difference in prices between Henry Hub and other gas trading hubs – across most of the United States. This week the Commission has issued a series of orders that certificate, in aggregate, more than several billion cubic feet of new gas pipeline capacity. This infrastructure can provide significant economic, reliability, and resiliency benefits. Gas is the marginal fuel in most wholesale power markets, and the wholesale price of electricity has dropped by double-digit amounts in 2015 3 and 2016 across the 1 United States remains largest producer of petroleum and natural gas hydrocarbons, U.S. ENERGY INFORMATION ADMINISTRATION: TODAY IN ENERGY (May 23, 2016), http://www.eia.gov/todayinenergy/detail.php?id=26352. 2 Short-Term Energy Outlook: Natural Gas, U.S. ENERGY INFORMATION ADMINISTRATION: ANALYSIS AND PROJECTIONS (Jan. 10, 2017), https://www.eia.gov/outlooks/steo/report/natgas.cfm. 3 Wholesale power prices decrease across the country in 2015, U.S. ENERGY INFORMATION ADMINISTRATION: TODAY IN ENERGY (Jan. 11, 2016), https://www.eia.gov/todayinenergy/detail.php?id=24492. Docket Nos. CP15-115-000 and CP15-115-001 -2- United States. 4 It is also true that carbon emissions from the power sector have dropped 24 percent from 2005 levels. 5 For comparison purposes, the Clean Power Plan targets a 32 percent reduction from 2005 levels by 2030, so the United States is three-quarters of the way there with 13 years to go. 6 While the increased use of renewable energy has helped, fuel switching from coal to gas has driven much of the reduction since gas emits about half the carbon as coal. In 2016, for the first time ever, more electricity was produced from gas than from coal. 7 Natural gas-fired generators, because of their fastramping characteristics, also complement renewable resources and can support a higher penetration of renewables. 8 Nevertheless, it is also true that the development of natural gas pipeline infrastructure has become increasingly controversial. 9 While FERC does not regulate the production of natural gas, methane emissions, or the use of fracking, many commenters have raised environmental concerns in our certificate proceedings. Moreover, because our certificate authority under the Natural Gas Act carries with it the ability to invoke eminent domain, property rights advocates have also objected to pipeline projects, alleging that private property is not being taken for a public use. As a result, the public interest in our work on energy projects is considerable. In order to respond to this 4 Wholesale power prices in 2016 fell, reflecting lower natural gas prices, U.S. ENERGY INFORMATION ADMINISTRATION: TODAY IN ENERGY (Jan. 11, 2017), http://www.eia.gov/todayinenergy/detail.php?id=29512. 5 U.S. Energy Information Administration, January 2017 Monthly Energy Review 185 (2017), https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf. 6 Fact Sheet: Overview of the Clean Power Plan, U.S. ENVIRONMENTAL PROTECTION AGENCY: THE CLEAN POWER PLAN (Aug. 3, 2015), https://www.epa.gov/sites/production/files/2015-08/documents/fs-cpp-overview.pdf. 7 Natural Gas Expected to Surpass Coal in Mix of Fuel Used for U.S. Power Generation in 2016, U.S. ENERGY INFORMATION ADMINISTRATION: TODAY IN ENERGY (Mar. 11, 2016), http://www.eia.gov/todayinenergy/detail.php?id=25392. 8 Pathways to Decarbonization: Natural Gas and Renewable Energy, JOINT INSTITUTE FOR STRATEGIC ENERGY ANALYSIS (Apr. 2015), http://www.nrel.gov/docs/fy15osti/63904.pdf. 9 See, e.g., Sierra Club, The Gas Rush: Locking America into Another Fossil Fuel for Decades 1 (2017) (noting concern over methane emissions and the “gas rush”), http://content.sierraclub.org/sites/content.sierraclub.org.coal/files/1466-Gas-RushReport%2004_web.pdf. Docket Nos. CP15-115-000 and CP15-115-001 -3- interest, I write separately to encourage the Commission to build on the progress that has been made to date and, in particular, to explore two other issues. One is how the Commission establishes need in doing its certificate reviews under section 7(c) of the Natural Gas Act. The certificate policy statement, which was issued in 1999, lists a litany of factors for the Commission to consider in evaluating need. 10 Yet, in practice, the Commission has largely relied on the extent to which potential shippers have signed precedent agreements for capacity on the proposed pipeline. This is a useful proxy for need, because presumably shippers would not sign up for capacity unless it was needed. But focusing on precedent agreements may not take into account a variety of other considerations, including, among others: whether the capacity is needed to ensure deliverability to new or existing natural gas-fired generators, whether there is a significant reliability or resiliency benefit; whether the additional capacity promotes competitive markets; whether the precedent agreements are largely signed by affiliates; or whether there is any concern that anticipated markets may fail to materialize. As an example of the latter consideration, LNG import terminals that were built during the early 2000 time period became stranded as shale gas increasingly substituted for LNG imports from overseas. There are other long-term issues that weigh in favor of examining whether other evidence, in addition to precedent agreements, can help the Commission evaluate project need. It is in the public interest to foster competition for pipeline capacity but also to ensure that the industry remains a healthy one, not subject to costly boom-and-bust cycles. Pipelines are capital intensive and long-lived assets. It is inefficient to build pipelines that may not be needed over the long term and that become stranded assets. Overbuilding may subject ratepayers to increased costs of shipping gas on legacy systems. If a new pipeline takes customers from a legacy system, the remaining captive customers on the system may pay higher rates. Under such circumstances, a cost-benefit analysis may not support building the pipeline. Adding to the uncertainty, there is fluidity in where gas is being produced in the United States. Some of the first-producing shale plays have already seen output decline as lower-cost basins, like the Marcellus and Utica, gained prominence. 11 Major new 10 Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC ¶ 61,227, at 61,748 (1999) (“The types of public benefits that might be shown are quite diverse but could include meeting unserved demand, eliminating bottlenecks, access to new supplies, lower costs to consumers, providing new interconnects that improve the interstate grid, providing competitive alternatives, increasing electric reliability, or advancing clean air objectives.”), clarified, 90 FERC ¶ 61,128, further clarified, 92 FERC ¶ 61,094 (2000). 11 U.S. Energy Information Administration, Drilling Productivity Report 2 (2017), http://www.eia.gov/petroleum/drilling/pdf/dpr-full.pdf. Docket Nos. CP15-115-000 and CP15-115-001 -4- production areas are being discovered that may impact gas flows on existing and proposed pipelines. 12 For decades, pipeline flows generally went from south to north and west to east. Production in the Marcellus and Utica led to flow reversals, with gas being transported from east to west and north to south. What happens to infrastructure developed to ship Marcellus and Utica gas west, if gas is cheaper to produce in Texas and Oklahoma? To the extent that producer-shippers are driving the development of new infrastructure, pipeline developers may now be exposed to market risk not present with shippers that are local distribution companies with a reliable rate base and predictable revenue stream. Similarly, it is important to ask what happens if basis differentials largely disappear at major gas trading hubs across the United States. A shipper would not need to transport gas from a more distant hub if it can be readily obtained for the same price from a closer one. This, too, might reduce the revenues of large interstate gas pipelines. The other issue the Commission should address is how we conduct our environmental reviews of pipeline projects. With respect to upstream impacts, the Commission has concluded in many cases that the pipelines do not cause the production of gas. Under the National Environmental Policy Act (NEPA), in my view, the strongest legal argument against causation is based on Department of Transportation v. Public Citizen. 13 Public Citizen holds that “where an agency has no ability to prevent a certain effect due to its limited statutory authority over the relevant actions, the agency cannot be considered a legally relevant ‘cause’ of the effect.” 14 Here, of course, FERC has no authority to regulate the production of natural gas; unless federal lands are involved, in general, that authority resides with the states. Despite the growing importance of Marcellus and Utica gas production – it was 22.5 Bcfd in 2016 and is projected to surpass 44 Bcfd by 2050 – the Commission has never conducted a comprehensive study of the environmental consequences of increased 12 USGS Estimates 20 Billion Barrels of Oil in Texas’ Wolfcamp Shale Formation, U.S. GEOLOGICAL SURVEY (Nov. 15, 2016), https://www.usgs.gov/news/usgs-estimates20-billion-barrels-oil-texas-wolfcamp-shale-formation. In addition, the SCOOP-STACK play in Oklahoma is another major recent find. Information on the Oklahoma Liquids Plays, NATURAL GAS INTEL: SHALE DAILY, http://www.naturalgasintel.com/oklahomaliqinfo. 13 14 541 U.S. 752 (2004). Id. at 770. See also EarthReports v. FERC, 828 F.3d 949, 956 (2016) (following Public Citizen); Sierra Club v. FERC, 827 F.3d 59, 68 (D.C. Cir. 2016) (same); Sierra Club v. FERC, 827 F.3d 36, 46 (D.C. Cir. 2016) (same). Docket Nos. CP15-115-000 and CP15-115-001 -5- production from that region. 15 Nor has the Commission performed a programmatic review of gas production in the different shale formations. This review is not required unless there is a proposed federal plan or program to develop the resources at issue. 16 FERC does not have such a plan or program with respect to shale gas. Thus, there is no legal requirement for the Commission to do such a review of gas production from shale formations. Even if not required by NEPA, in light of the heightened public interest and in the interests of good government, I believe the Commission should analyze the environmental effects of increased regional gas production from the Marcellus and Utica. The Department of Energy has conducted a similar study in connection with the exercise of their obligations under Section 3(a) of the Natural Gas Act. 17 Where it is possible to do so, the Commission should also be open to analyzing the downstream impacts of the use of natural gas and to performing a life-cycle greenhouse gas emissions study, both of which DOE has conducted in issuing permits for LNG exports. This information may be of use to the Commission, the public, and industry in examining the broader issues raised in certification proceedings. Beyond the two issues I have highlighted, there may well be other issues that could usefully be examined by the Commission. Such an examination would be consistent with the best traditions of FERC, where, time and again, the Commission has sought the views of a diverse range of stakeholders when exploring important issues. Indeed, a recent example of such outreach occurred after the EPA issued its proposed rulemaking on the Clean Power Plan; FERC held a series of technical conferences to examine the implications of the Clean Power Plan for the electric industry. As important as infrastructure development is, it must also occur through processes that continue to promote public participation, transparency, and confidence. 15 U.S. Energy Information Administration, Annual Energy Outlook 2017 with Projections to 2050 53 (2017), http://www.eia.gov/outlooks/aeo/pdf/0383 (2017).pdf. 16 17 Kleppe v. Sierra Club, 427 U.S. 390, 400-01 (1976). See U.S. Department of Energy, Addendum to Environmental Review Documents Concerning Exports of Natural Gas from the United States 19 (Aug. 2014), http://energy.gov/sites/prod/files/2014/08/f18/Addendum.pdf. Docket Nos. CP15-115-000 and CP15-115-001 -6- For all those reasons, I respectfully offer this separate statement. ______________________ Norman C. Bay Commissioner