CARI BOYCE Vice President Environmental & Energy Policy 410 S. Wilmington Street, NCRH 12 A Raleigh, NC 27601 Tel: 919-546-7314 cari.boyce@duke-energy.com December 4, 2014 VIA Electronic Mail Environmental Protection Agency EPA Docket Center (EPA/DC) Mail Code: 28221T Attn: Docket ID No. EPA-HQ-OAR-2013-0602 1200 Pennsylvania Avenue, N.W. Washington, DC 20460 Subject: Correction to Duke Energy Comments on the Carbon Pollution Emission Guidelines For Existing Stationary Sources: Electric Utility Generating Units; Proposed Rule. 79 Fed. Reg. 34,830 (June 18, 2014) After Duke Energy’s comments on the above referenced proposed rule were submitted on December 1, 2014, an error was discovered on page 2 of the comments. The previously submitted comments contain the following statement. “We have invested over $9B in new state-of-the art generation, which has allowed the retirement of over half of our coal fleet (6800 megawatts of capacity). In 2005, about two-thirds of our generation came from coal.” The statement should have been as follows. “We have invested over $9B in new state-of-the art generation, allowing for the retirement of about one quarter of our coal fleet and large oil-fired fleet (6,800 megawatts of capacity by 2018), which includes over half of our North Carolina coal fleet.” The attached comments reflect this corrected statement. Should you have any further questions regarding these comments, please contact Mike Stroben, Environmental & Energy Policy Director at michael.stroben@duke-energy.com or (704) 373-6846. Sincerely, Cari Boyce Vice President, Environmental & Energy Policy CARI BOYCE Vice President Environmental & Energy Policy 410 S. Wilmington Street, NCRH 12 A Raleigh, NC 27601 Tel: 919-546-7314 cari.boyce@duke-energy.com December 1, 2014 VIA www.regulations.gov Environmental Protection Agency EPA Docket Center (EPA/DC) Mail Code: 28221T Attn: Docket ID No. EPA-HQ-OAR-2013-0602 1200 Pennsylvania Avenue, N.W. Washington, DC 20460 Subject: Duke Energy Comments on the Carbon Pollution Emission Guidelines For Existing Stationary Sources: Electric Utility Generating Units; Proposed Rule. 79 Fed. Reg. 34,830 (June 18, 2014) Duke Energy Business Services, LLC (Duke Energy), on behalf of Duke Energy Carolinas, LLC, Duke Energy Indiana, Inc., Duke Energy Ohio, Inc., Duke Energy Kentucky, Inc., Duke Energy Florida, Inc., Duke Energy Progress, Inc. and Duke Energy Commercial Power submits the attached comments to the Environmental Protection Agency (EPA) on the proposed Carbon Pollution Emission Guidelines For Existing Stationary Sources: Electric Utility Generating Units. Should you have any further questions regarding these comments, please contact Mike Stroben, Environmental & Energy Policy Director at michael.stroben@duke-energy.com or (704) 373-6846. Sincerely, Cari Boyce Vice President, Environmental & Energy Policy Attachment cc: Diane Denton Mike Stroben Amy Vasu (U.S. EPA) COMMENTS OF DUKE ENERGY on the CARBON POLLUTION EMISSION GUIDELINES FOR EXISTING STATIONARY SOURCES: ELECTRIC UTILITY GENERATING UNITS; PROPOSED RULE DOCKET ID No. EPA-HQ-OAR-2013-0602 79 Fed. Reg. 34,830 (June 18, 2014) December 1, 2014 Corrected December 4, 2014 Table of Contents I. II. Introduction and Executive Summary ................................................................................ 1 A. Any EPA Proposal to regulate Greenhouse Gas Emissions Must Conform With the Requirements of the Clean Air Act. .................................................................. 3 B. The Proposed 2020-2029 Interim Compliance Period Could Result in Significant Stranded Assets for Customers and Should be Eliminated. .................................... 4 C. Building Block 1 - The Assumed 6 Percent Heat Rate Improvement (HRI) . Target For Coal-Fired EGUs is Unachievable. .................................................................. 5 D. Building Block 2 - The EPA Has Not Demonstrated That Its Assumed Redispatch in Generation From Coal-Fired EGUs to NGCC Units is Achievable ................... 5 E. Building Block 3 – The EPA’s Proposed Treatment of Renewables and Nuclear in State Goal-Setting is Inappropriate. ........................................................................ 6 1. Renewable Energy....………………………………………………………..6 2. Nuclear Energy .............................................................................................. 7 F. Building Block 4 – The EPA’s Proposed Targets for End-Use Energy Efficiency Are Unreasonable.................................................................................................... 8 G. The EPA Has Made Numerous Errors in its State Goal Calculations .................... 9 H. The EPA Must Clarify the Treatment of New NGCC Units. ............................... 10 I. The EPA Should Use a Multi-Year Historic Baseline Period for State Goal Setting. .................................................................................................................. 10 The Proposed Guidelines Are Inconsistent With the Focus of Section 111 of the Clean Air Act .............................................................................................................................. 11 A. B. Section 111 Authorizes Standards of Performance That Are Achievable for Individual Sources in a Source Category Based on Measures Those Sources Can Implement Themselves. ........................................................................................ 12 1. The Text of Section 111. .............................................................................. 12 2. Context of Section 111 Within the CAA. .................................................... 14 3. The History of EPA’s Implementation of Section 111. ............................... 15 The EPA’s Proposed Action in The Proposed Guidelines Deviates So Far from The CAA as to Be Unrecognizable as an Exercise of Section 111 Authority. ..... 17 1. The EPA’s Proposed Guidelines Impermissibly Base Standards of Performance on Measures that Go Beyond the Regulated Source Itself. .... 17 2. The EPA Cannot Consider Reduced Utilization of Regulated Sources as BSER............................................................................................................ 21 3. The Proposed Guidelines Are Based on Measures that States and the EPA Cannot Enforce Against Regulated Sources. ............................................... 24 C. The EPA’s 111(d) Proposed Guidelines Are Inconsistent With the Agency’s 111(b) Proposal. .................................................................................................... 31 D. The EPA’s Proposed Guidelines Are Unconstitutional. ....................................... 34 E. The EPA Has Not Demonstrated That its Proposed BSER Has Been Adequately Demonstrated. ....................................................................................................... 36 III. The EPA Cannot Regulate EGUs Simultaneously Under Sections 111(b) and 111(d) of the CAA. ........................................................................................................................... 38 IV. State Implementation Issues. ............................................................................................ 41 V. A. Despite the EPA’s Claims, States Have Little To No Flexibility in Their Ability To Meet the Proposed State Goals. ....................................................................... 41 B. The Interim Compliance Period Should be Eliminated as a Way to Provide States With More Flexibility, to Avoid Reliability Problems, and Provide a Reasonable Period of Time to Comply. ................................................................................... 42 1. Many State Interim Goals Are Front-Loaded……...…………………...….43 2. The Proposed Schedule Leaves Insufficient Time Between Approval of State Plans and 2020, the Start of the Interim Compliance Period……...…45 3. The Interim Compliance Period Will Create Substantial Stranded Investment………………………………………………………………….47 4. The Interim Compliance Period Could Create System Reliability Problems and Uneconomic Compliance Decisions…………………………………..48 5. The EPA Has Discretion in Setting Compliance Schedules Under Section 111(d)………………………………………………………………………51 Building Block 1 ............................................................................................................... 52 A. The 6 Percent Heat Rate Improvement Target For Coal-Fired EGUs Assumed For Building Block 1 is Unachievable. ....................................................................... 52 1. The EPA’s Use of a Single Report Undermines its Building Block 1 Six Percent Heat Rate Improvement Goal……………………………………..55 2. The EPA’s Assumption That “Best Practices” Can Improve the Heat Rate of the Coal-Fired EGU Fleet By Four Percent On Average Is Not Supported By Data………………………………………………………………...…..56 3. The EPA’s Bin Analysis Does Not Demonstrate That Most Heat Rate Variability Can Be Attributed to Deficient O&M Practices……......….…..58 4. The EPA Inappropriately Considered Duke Energy’s Gibson Unit 1 As a Unit That Has Demonstrated a 3 to 8 Percent Heat Rate Reduction............60 B. VI. VII. 5. The EPA Did Not Account For Increases in Heat Rate From the Installation of Pollution Control Technologies in Its Development of the HRI Targets……………………………………………………………………...62 6. The EPA Should Not Have Considered Units That Are Expected to Close When Assessing Fleet-Wide Heat Rate Improvement Potential Through Statistical Analysis.……...………….……………….………......….......….64 7. The EPA Has Not Provided a Reasonable Basis For the Conclusion That “Equipment Upgrades” Can Improve Heat Rates By Two Percent.....….....64 8. The EPA Has Not Determined Which "Equipment Upgrades” Already May Have Been Implemented…..…………………………………………….…66 9. The EPA Did Not Address the Adverse Heat Rate Impacts Due to Changes in Operation and Displacement of Generation Resulting From Building Blocks 2, 3, & 4…………..………………………………………....…..…67 10. The EPA Has Overestimated the Cost Savings Associated With Heat Rate Improvement...….……………………………...……..………...….…...….69 11. The EPA Should Defer to the States to Determine the Appropriate Levels of Heat Rate Improvement. .............................................................................. 71 New Source Review Issues. .................................................................................. 72 Building Block 2 ............................................................................................................... 76 A. The EPA Has Not Shown That Building Block 2 Has Been Adequately Demonstrated Or Is Achievable. ........................................................................... 76 B. The EPA Erred in its Calculation of NGCC Capacity Factors. ............................ 82 C. The EPA Should Reaffirm its Proposal to Exclude Gas Co-Firing or Conversion of Coal-Fired EGUs as Part of BSER ................................................................... 84 D. Miscellaneous Building Block 2 Issues ................................................................ 88 1. The EPA Has Provided No Technical Justification For Using MWhs From Increased Utilization of NGCC Units to Decrease Generation From Coal Units Before Decreasing Generation From Oil/Gas Steam Units. .............. 88 2. Duke Energy Supports the EPA’s Proposal Not to Consider New NGCC Capacity As a Component of BSER for Building Block 2 .......................... 89 3. States Should Have Discretion to Include New NGCC Emissions and Generation When Demonstrating Compliance Under a Rate-Based Program ……………………………………………………………………………...92 Building Block 3 ............................................................................................................... 93 A. Issues Related to the EPA’s Proposed State Renewable Energy Targets ............. 93 1. The EPA Inappropriately Set the State Renewable Energy Targets Used in the State Goal Calculations…...……………………………...…………….93 2. B. VIII. The EPAShould Exclude Soon to Expirt federal Tax Incentives When Evaluating the Cost of RE…………………………..………………...……99 Issues Related to the EPA’s Proposed Treatment of Existing, Under Construction, and New Nuclear................................................................................................. 115 1. The EPA’s Proposed Treatment of Existing Nuclear Capacity is Inappropriate and Must Be Changed. ........................................................ 115 2. Existing Nuclear Units That are Relicensed Beyond 60 Years Should be Treated as New Capacity…...……....…………………...………………..120 3. The EPA Should Not Include Under Construction Nuclear Units in State Goal Computations. ................................................................................... 121 4. Duke Energy Supports the EPA’s Proposed Treatment of New Nuclear Generating Units and Uprating of Existing Nuclear Units. ....................... 122 5. The EPA Should Recognize that Generation From New Nuclear Power Plants Will Cross State Boundaries and Should Allow the Importing State to Factor the Generation into its Compliance Demonstration........................ 123 Building Block 4 ............................................................................................................. 124 A. B. Customer Behavior Impacts Adoption of Demand-Side Energy Efficiency Programs ............................................................................................................. 124 1. The Price of Electricity Is An Important Factor Affecting Adoption of Energy Efficiency Measures. ..................................................................... 126 2. The EPA Has Not Accounted for the Fact That Demand-Side Energy Efficiency Programs Are Maturing. ........................................................... 128 3. The Potential Lack of Availability and the Cost of More Energy-Efficient Equipment Impacts Customer Adoption. ................................................... 130 4. Regional Climate Impacts the Adoption of Energy Efficiency Programs. 131 5. Customer Mix Impacts the Savings Each State Is Able to Achieve Through Demand-Side Energy Efficiency Measures. .............................................. 131 6. Socioeconomic Demographics Impacts Customer Behavior. .................... 133 Annual Incremental Energy Savings Targets. .................................................... 133 1. Annual Incremental Savings Targets of 1.5 Percent And 1.0 Percent Are Not Sustainable. ................................................................................................ 134 2. Increasing the Annual Incremental Savings Target to 2.0 Percent Is Not Feasible. ..................................................................................................... 140 3. Alternative Sources of Data Should be Utilized. ....................................... 140 C. Incorporating Renewable Energy and Demand-Side Energy Efficiency Measures Under a Rate-Based Approach............................................................................ 141 D. Quantification, Monitoring, and Verification of Demand-Side Energy Efficiency Measures. ............................................................................................................ 141 1. Harmonizing State Practices Through a Technical Reference Manual Would Not Be a Constructive Undertaking. .......................................................... 142 2. Guidance Limited to Well-Established Programs is a Setback to Developing New and Innovative Programs. .................................................................. 143 3. The EPA View of Demand-Side Energy Efficiency Measure Life Concept is Incorrect. .................................................................................................... 144 4. Behavioral Demand-Side Energy Efficiency Programs Should Be Included. . .................................................................................................................... 145 5. Non-Energy Benefits Should Not Be Included in EM&V......................... 146 6. Line Loss Consistency Should be Included in EM&V. ............................. 146 7. Hourly Savings Profile. .............................................................................. 147 8. Net Versus Gross Reporting of Energy Efficiency Savings. ..................... 148 9. EM&V Process for Codes and Standards. ................................................. 148 10. EM&V Certification Process. .................................................................... 149 11. State Plan Documentation. ......................................................................... 149 12. Treatment of Interstate Effects................................................................... 150 IX. Alternate Goals ............................................................................................................... 151 X. The EPA Has Made Numerous Errors in its Goal Calculations That Must Be Corrected and State Goals Revised Accordingly............................................................................. 152 A. Errors Related to NGCC Facilities in the EPA’s Application of Building Block 2 to State Goal Calculations. .................................................................................. 152 1. The EPA Should Have Used Net Generating Capacity Instead of Nameplate Capacity for Natural Gas Combined Cycle Units in its Application of Building Block 2………………………………………… ........................ 152 2. The EPA Used Erroneous NGCC Capacity Under Construction in its Application of Building Block 2 for Calculating the North Carolina Goals ……………………………………...……………………………………..155 3. The EPA Incorrectly Treated Two Duke Energy NGCC Facilities in North Carolina as Existing Units Instead of Under Construction Units in its Application of Building Block 2………………. ....................................... 156 4. The EPA Should Not Include “Under Construction” NGCC Capacity When Implementing Building Block 2 in State Goal Calculations…...…………158 5. The EPA’s Use of Average 2012 NGCC Emission Rates When Applying Building Block 2 to State Goal Calculations is Inappropriate……………160 6. The EPA Must Exclude NGCC Units that Do Not Meet the Applicability Criteria for Stationary Combustion Turbines rom State Goal Calculations…………………………………………………………….....162 B. The EPA Should Not Give Further Consideration to the Goal-Setting Methodology Presented in the October 30, 2014 NODA………………………164 XI. The EPA Should Use a Multi-Year Historic Baseline Period for State Goal Setting..... 166 XII. Monitoring, Recordkeeping and Reporting .................................................................... 169 XIII. A. Measurement of CO2 Emissions ......................................................................... 169 B. Monitoring and Reporting of Electric Output. .................................................... 171 1. Monitoring of Net Electrical Output Should Not Be Required. ................ 172 2. Requiring the Use of ANSI Standard C12.20 Is Not Justified. ................. 173 3. Monitoring and Reporting of Useful Thermal Output. .............................. 175 4. Monitoring Plan and Quality Assurance and Quality Control (“QA/QC”) Testing........................................................................................................ 176 5. Use of Specific Methods for Flow RATAs and Baseline Adjustments Following a Change in Method.................................................................. 177 6. EGU Recordkeeping Requirement. ........................................................... 180 The EPA Must Provide Greater Clarity Around the Approach it Envisions for States to Perform Rate-to-Mass Translations. ............................................................................... 181 XIV. Using Gross vs. Net to Set Existing Source Requirements ............................................ 184 XV. Potential Reliability Impacts ........................................................................................... 186 XVI. State Plans ....................................................................................................................... 188 A. The EPA’s Proposal for Modifying a State Plans is Inappropriate and Must Be Revised. ............................................................................................................... 188 B. States Should Have the Ability to Take Credit in Compliance Demonstrations for Reduced or Avoid CO2 Emissions Occurring Starting from the End of the Base Period. ................................................................................................................. 190 C. States that Import Electricity Should Not Have to Discount EE Savings........... 193 XVII. Inequities and Other Shortcomings in the Proposed Guidelines. ................................... 195 A. The State Goal Computation Results in Inequitable Regulation of States and Affected EGUs………………………………………………………………….195 B. The Disparate Impacts of the Proposed Guidelines Across States Illustrate the Arbitrary and Capricious Nature of the Proposed Guidelines. ........................... 198 XVIII. The Proposed Guidelines Unlawfully Expands the EPA’s Authority, Obstructs States’ Flexibility in Developing Section 111(d) Programs, and Ignores the Obligation to Identify Appropriate Subcategories of Sources. ........................................................................... 203 A. The EPA’s Proposed Guidelines Exceed CAA Authority by Setting Mandatory Emissions “Guidelines” and Does Not Fulfill Its Duty to Evaluate Subcategories of Sources……………………………………………………………………….203 B. Consideration of a Facility’s “Remaining Useful Life” in Applying Standards of Performance. ....................................................................................................... 209 C. The EPA’s Four Building Blocks Take Away State Flexibility Rather Than Provide Flexibility .............................................................................................. 212 D. The Process and Timing for Submittal of State Plans Obstructs State Flexibility in Developing Plans ................................................................................................ 215 XIX. The EPA’s Calculation of the Costs of the Clean Power Plan Contains Errors That Results in a Substantial Underestimate of the Policy’s Cost .......................................... 217 XX. Conclusion ...................................................................................................................... 217 Attachments Attachment 1: Comment on EPA’s Compliance Cost Estimate for the Clean Power Plan COMMENTS OF DUKE ENERGY on the CARBON POLLUTION EMISSION GUIDELINES FOR EXISTING STATIONARY SOURCES: ELECTRIC UTILITY GENERATING UNITS; PROPOSED RULE DOCKET ID No. EPA-HQ-OAR-2013-0602 79 Fed. Reg. 34,830 (June 18, 2014) I. Introduction and Executive Summary In July 2013, President Obama announced a “Climate Change Action Plan” which included a commitment to regulate carbon dioxide (“CO2”) through the Executive Branch if Congress failed to pass comprehensive federal climate legislation. In the absence of such legislation, on June 18, 2014, the United States Environmental Protection Agency’s (“EPA” or “Agency”) “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units” proposed rule (“Proposed Guidelines” or “CPP” or “Clean Power Plan”) was published in the Federal Register.1 Duke Energy Business Services LLC (“Duke Energy”) submits the following comments on the EPA’s Proposed Guidelines. In addition to the following comments, Duke Energy supports the comments submitted by the Utility Air Regulatory Group. This proposed rule is significant for the entire electric utility sector and for Duke Energy and its customers. As the largest electric power holding company in the United States, Duke Energy’s generating capacity is 57,700 megawatts. Through our 6 regulated utilities, we produce and deliver electricity to 7.2 million homes and businesses located in six states. About 21 million people depend on us to keep their lights and air conditioning on, not to mention the 1 79 Fed. Reg. at 34,830. 1 hospitals, airports, commercial businesses, and manufacturers who depend on us for reliable electric service 24 hours a day, 7 days a week. Duke Energy’s regulated utility business has a balanced mix of energy resources – including 19 coal-fired steam stations, 6 nuclear stations (we own and operate the largest regulated nuclear fleet in the country), 39 natural gas stations, 35 hydro stations , as well as a growing portfolio of renewable energy sources. We operate in regulated and deregulated markets, including several that have Regional Transmission Organizations or RTOs. We operate commercial renewable and transmission businesses in the United States, as well as generating facilities in Latin America. This diversity gives Duke Energy a unique perspective when it comes to advocating for sound energy policies for the Country. With this context, Duke Energy supports policies that will result in reasonable decreases in greenhouse gas (“GHG”) emissions over time. An effective policy must balance emission reductions with impacts to our customers’ electric rates, our states’ economies, and the reliability that our customers demand. Over the past decade, Duke has been focused on modernizing our generation fleet. We have invested over $9B in new state-of-the art generation, allowing for the retirement of about one quarter of our coal fleet and large oil-fired fleet (6,800 megawatts of capacity by 2018), which includes over half of our North Carolina coal fleet. In 2005, about two-thirds of our generation came from coal. Today coal accounts for less than 50 percent of our generation, and almost one third of our generation comes from non-emitting resources such as renewables and nuclear. Duke Energy has invested more than $7.5 billion on state-of-the-art environmental control equipment for its power plants since 1999. And we plan to spend another $5-6 billion 2 over the next 10 years. This estimate does not include the cost to comply with the EPA’s Proposed Guidelines. Duke Energy has a jump start on reducing CO2 emissions. To date, we have reduced our CO2 emissions by 20 percent from 2005 levels while also achieving sulfur dioxide reductions of 84 percent and nitrogen oxides reductions of 63 percent during the same time period. As Duke Energy evaluates policy proposals, we seek to ensure that our customers get the full benefit of these early actions and investments. Implementing the EPA’s Proposed Guidelines would fundamentally alter how electricity is generated, delivered and consumed in the country. This is a matter typically left to states. In this regard, the EPA’s Proposed Guidelines attempt to establish a national energy policy through a section of the Clean Air Act (“CAA”) never designed for that purpose. Duke Energy believes that creating a national energy policy would best be accomplished through comprehensive federal legislation rather than a regulatory approach. As such there are significant flaws with the EPA Proposed Guidelines, as outlined below and explained in these comments: Following are the key areas of focus in Duke Energy’s comments: A. Any EPA Proposal to Regulate Greenhouse Gas Emissions Must Conform With the Requirements of the Clean Air Act. The CAA was passed more than 40 years ago and was never designed to implement national energy policy or to deal with the global issues associated with greenhouse gas emissions. A standard of performance under section 111 of the CAA must be achievable with adequately demonstrated, commercially available technology that can be achieved by the individual regulated sources (coal-fired electric generating units (“EGUs”)). The EPA’s proposed best system of emissions reduction (“BSER”) is unprecedented because it proposes to include the entire electric system, including sources that do not produce power or any emissions to establish 3 the proposed standards states must meet. The fundamental departure from established statutory requirements in the EPA’s Clean Power Plan is the Agency’s assertion that the BSER for coalfired EGUs may include measures that would either directly or indirectly reduce a source’s utilization or that are not within the control of individual sources. The EPA’s redefinition of what measures may constitute a “system of emission reduction” is contrary to over 40 years of the EPA’s consistent interpretation and implementation of section 111. Questions of statutory authority aside, there are several flaws with the proposal, specifically: B. The Proposed 2020-2029 Interim Compliance Period Could Result in Significant Stranded Assets for Customers and Should be Eliminated. The proposed interim compliance period, which begins in 2020 and ends in 2029, has the real potential to create reliability problems and stranded investments, and does not provide adequate time for planning for the large amount of coal unit retirements that could occur before 2020, including the planning, approval and implementation for replacement generation, upgraded and expanded transmission and distribution facilities and new natural gas pipeline infrastructure. There simply isn’t enough time between when the EPA might approve a state plan (possibly as late as mid-2019) and 2020, the start of the interim compliance period, to develop utility-specific compliance plans, have them approved, and implement those plans. The EPA’s own analysis of the proposed rule predicts that 46 to 49 gigawatts (“GW”) of coal-fueled generation will be shut down by no later than 2020 as a result of the interim compliance plan. Beyond the practical, logistical impossibility of achieving this and ensuring no unreasonable risks to reliability in the meantime, forcing the premature shutdown of existing coal-fired EGUs by 2020 will result in billions of dollars in stranded assets. Such an outcome would be unacceptable. The EPA should 4 eliminate the interim compliance period and allow states to develop their own glide path for meeting their 2030 requirements. C. Building Block 1 - The Assumed 6 Percent Heat Rate Improvement (“HRI”) Target For Coal-Fired EGUs is Unachievable. The ability to improve the heat rate of a coal-fired EGU is unit specific due to unique differences among coal-fired EGUs that affect potential HRI opportunities at individual units. The EPA’s study of a small sample of units does not adequately represent what HRI can be achieved at each individual unit. There are several factors that Duke Energy believes must be considered: o An assessment of the HRI opportunities at the unit level so HRIs that have already been undertaken across the fleet of coal-fired EGUs can be recognized. o That adverse heat rate impacts due to the additional cycling, increased load variability, and reduced load factors that would result from the displacement of coalfired generation from Building Blocks 2, 3, & 4 that will serve to increase rather than reduce average coal-fired EGU heat rates and potentially counteract any HRIs made in Building Block 1. o That adverse heat rate impacts result from the installation of pollution control technologies which must be accounted for in the development of any HRI targets. o The potential for New Source Review impediments to the implementation of HRIs. Duke recommends the EPA defer to the states to determine the level of HRI that is appropriate for each existing coal-fired EGU in each respective state. D. Building Block 2 - The EPA Has Not Demonstrated That Its Assumed Redispatch in Generation From Coal-Fired EGUs to Natural Gas Combined Cycle Units is Achievable. 5 Not only is the EPA’s proposal to displace coal-fired generation with generation from natural gas combined cycle (“NGCC”) units outside the scope of the CAA, but its Building Block 2 analysis is fundamentally flawed. The EPA’s determination that 10 percent of the NGCC units operated at a capacity factor of 70 percent or greater in 2012 does not show that operation of the entire fleet of NGCC units at a 70 percent capacity factor has been adequately demonstrated as required by section 111 of the CAA. The EPA’s analysis does not account for factors that limit the ability to increase utilization of NGCC units, such as technical limitations, permit limits, insufficient natural gas pipeline capacity, and inadequate electric transmission infrastructure to support that level of generation redispatch from coal-fired EGUs to NGCC units by 2020, the year the EPA has assumed the full redispatch would occur. Other NGCC units will not be able to generate sufficiently above a 70 percent capacity factor to make up for units that are incapable of operating at a 70 percent capacity factor. The Agency has also not considered the significant impact that this increased natural gas demand could have on natural gas prices, and therefore on the cost for NGCC units to achieve the proposed 70 percent capacity factor target. E. Building Block 3 – The EPA’s Proposed Treatment of Renewables and Nuclear in State Goal-Setting is Inappropriate. 1. Renewable Energy The inclusion of renewable energy (“RE”) as a component of the EPA’s BSER determination for coal-fired EGUs is clearly not authorized by the CAA. In addition, the EPA’s proposed approach to setting state-level RE targets is flawed based on determining RE targets for states within regions based on an average of existing state renewable portfolio standard (“RPS”) targets within a region. For example, the EPA set RE targets for South Carolina, Florida, and Kentucky based exclusively on the RPS requirements in North Carolina because North Carolina 6 is the only state in the southeast with an RPS requirement. Renewable requirements for South Carolina, Florida and Kentucky should not be set based on a policy decision made years ago by the North Carolina legislature because of each state’s unique RE resource availability and economics of deploying RE generation. In addition, some state RPS requirements include enduse energy efficiency as a component of the target along with the ability to purchase RE credits from out of state, effectively reducing the amount of RE that must be produced in state. North Carolina is a case in point. The EPA incorrectly interpreted and applied the North Carolina RPS based on the program’s requirement of 10 percent in 2020. When corrected for the 40 percent component of energy efficiency and the 25 percent allowable purchase of out-of-state RE credits, as well as different requirements for public utilities, the correct number for North Carolina is 4.85 percent, which would lower the RE target for all states in the Southeast region, including South Carolina, Florida, and Kentucky. The EPA made similar errors in its interpretation of state RPS programs in regions that include Indiana and Ohio that when corrected result in a lowering of the Indiana and Ohio RE targets. Of the three Alternative Approaches considered by the EPA to set state RE targets, only a modified version of determining the avoided costs of RE for each state is used by utilities and regulatory commissions. The first two proposed Alternative Approaches are methodologically flawed and should not be used. 2. Nuclear Energy Although nuclear power is the single greatest CO2 mitigation option available in the power sector, that fact does not authorize the EPA to use it when setting CO2 emission standards for fossil fuel-fired EGUs. Putting that statutory issue aside, the EPA’s proposal to include 5.8 percent of existing nuclear capacity as part of the BSER for coal-fired EGUs because the Agency determined that 5.8 percent of the country’s existing nuclear generating capacity is at risk of premature retirement is without merit. The EPA should not finalize any guidelines for coal-fired 7 EGUs that include any amount of existing nuclear generation in its BSER determination. If the EPA wants to provide an incentive in its guidelines for the continuing operation of existing nuclear units, it should consider any generation from an existing nuclear unit that receives a license extension beyond 60 years to be “new nuclear” and allow states to include 100% of the generation occurring beyond year 60 in their compliance demonstrations. The EPA should remove all currently under construction nuclear units from the BSER determinations for South Carolina, Georgia, and Tennessee. Duke Energy supports the EPA’s proposal to allow both new nuclear generating units and uprating of existing nuclear generating units to be included as components of state plans and therefore factored into state compliance. F. Building Block 4 – The EPA’s Proposed Targets for End-Use Energy Efficiency Are Unreasonable. As a threshold issue, it is Duke Energy’s view that the use of demand-side energy efficiency in setting a section 111 CO2 emission standard for coal-fired EGUs is unlawful. In addition, the approach is seriously flawed. The EPA, in its assessment of opportunities to increase the deployment of demand-side energy efficiency measures in each state as part of Building Block 4, failed to take into account the fact that customer behavior is beyond the control of public utilities. Customer adoption of demand-side energy efficiency programs depends on a number of factors including, but not limited to, the cost of electricity, the maturity of existing programs, the incremental cost of a more efficient technology to the customer, the availability of more efficient equipment, a state’s climate, its customer mix, and the socioeconomic demographics within a state. These factors vary significantly from state to state. The EPA’s generalized macro assumptions regarding demand-side energy efficiency potential applied uniformly across all states is not appropriate because it does not properly account for 8 these factors. For instance, the EPA looked at the annual incremental energy efficiency savings rates achieved by only three states (including the District of Columbia) in 2012, and the 2020 annual incremental energy efficiency savings rate goals for nine states and leapt to the conclusion that all states are capable of achieving a 1.5 percent annual incremental energy efficiency savings rate. The EPA’s overly simplistic and rather narrow analysis fails to demonstrate the applicability let alone feasibility of an annual incremental savings rate of at least 1.5 percent across the broader 50 states. If the EPA continues to believe that demand-side energy efficiency is a part of the best system of emission reductions for coal-fired EGUs, it should defer to the states to determine the appropriate level of energy efficiency for their unique circumstance. G. The EPA Has Made Numerous Errors in its State Goal Calculations. The EPA’s analysis makes several errors in the state goal calculations with respect to its application of Building Block 2 – redispatch from coal to NGCC units - that results in proposed state goals significantly lower than they would otherwise be. For example, the EPA used the nameplate capacity of NGCC units when calculating the megawatt-hours (MWh) that would be produced by NGCC units at a 70 percent capacity factor and used to displace generation from coal-fired EGUs. The EPA should have used the net capacity of NGCC units, which is lower than nameplate capacity because net capacity is what a unit can actually supply to the electrical grid. The use of nameplate capacity results in an overstatement of the MWh that can be supplied to the grid at a 70 percent capacity factor. This error applies to all states. Specific to NC are several errors the EPA made regarding the amount of existing and under construction NGCC capacity it included in its NC goal calculation. First, the EPA included 1,627 megawatts (“MW”) of NGCC capacity as under construction that simply does not exist. Second, the EPA incorrectly treated two Duke Energy NGCC facilities recently completed 9 as existing units in the 2012 base year. One of the units (Dan River) did not begin operation until very late in the year and the other (Lee) did not commence operations until 2013. Both units should be considered under construction units for purposes of the NC goal calculation. H. The EPA Must Clarify the Treatment of New NGCC Units. The EPA correctly proposed that new NGCC units are not considered part of its BSER determination for coal-fired EGUs and therefore are not included in the calculation of state goals. Yet the EPA requested comment on whether new NGCC units should be included in its BSER determination. New NGCC units are regulated under section 111(b) of the CAA and cannot be simultaneously regulated under section 111(d). Therefore, they cannot be considered part of BSER for coal-fired EGUs under section 111(d). Although new NGCC units are outside the scope of the section 111(d) program, it would be permissible for a state that employs the ratebased approach under section 111(d) to allow the megawatt hours generated by these newly constructed NGCC units to be included in a state’s compliance demonstration. This approach would be similar to how the EPA proposes to treat renewable energy. I. The EPA Should Use a Multi-Year Historic Baseline Period for State Goal Setting. The EPA has proposed to use a single year, 2012, as the baseline period for calculating each state’s CO2 emission reduction target. However, it is inappropriate to use any single year as a baseline to represent the electric power sector. There is considerable year-to-year variability due to many factors including economic conditions, weather fluctuation, , changes in fuel prices, and significant unplanned and planned generating unit outages. With regard to fuel prices, natural gas prices in 2012 were at their lowest level since before 2000 (the 2012 annual average Henry Hub price was $2.75 per mmBtu), lower than today’s price, and lower than any natural gas price the EIA projects into the future. A multi-year baseline period consisting of 2009 – 10 2012 would be a more representative baseline period than 2012 alone. Specifically, Duke Energy recommends that for each state the EPA calculates baselines for 2009 to 2012 and selects as the baseline the average of the highest three out of four years. II. The Proposed Guidelines Are Inconsistent With the Focus of Section 111 of the Clean Air Act. Section 111 of the CAA is clear as to the subject and nature of standards of performance for new and existing sources under its provisions. A standard of performance under section 111 must be achievable for individual regulated sources using measures that the source’s owner can integrate into the design or operation of the sources themselves. Section 111 has existed, with only minor changes, for over 40 years, and in that time the EPA has applied it with total consistency on this point. A standard of performance cannot be based on actions taken beyond the source2 itself that somehow reduce the source’s utilization. Nor can it be based simply on directly requiring a source to reduce its operations. Yet instead of defining a category of regulated sources, identifying the best system of emission reduction (“BSER”) that any individual source can incorporate into its design, and then allowing states to determine what standards are achievable for sources based on that BSER and consideration of other factors, the EPA has started at the end by defining an inflexible emissions goal for each state and then requiring states to impose whatever obligations are necessary to achieve that goal. To accomplish this unprecedented approach, the EPA proposes to base its “emission guidelines” on actions that reach beyond individual regulated sources and impose obligations on entities with no emissions at all, or to simply mandate that regulated sources curtail their operations altogether. Neither approach has any basis in the statute. Indeed, the 2 Also referred to as “outside-the-fence.” 11 EPA’s proposed approach is totally inconsistent with the CAA and with the Agency’s own 40year history of interpretation and implementation of section 111. The EPA’s proposal clearly exceeds the Agency’s authority under the CAA. The EPA should withdraw the Proposed Guidelines and reissue a proposal that conforms with the legal requirements of the CAA. A. Section 111 Authorizes Standards of Performance That Are Achievable for Individual Sources in a Source Category Based on Measures Those Sources Can Implement Themselves. To fully understand how dramatically the EPA has departed from its authority in this rulemaking, it is important to first understand the nature and limits of the CAA’s section 111 regulatory program as it has been defined by the text of that provision, by its context within the remainder of the CAA, and by more than 40 years of consistent EPA implementation. This program begins and ends with the regulated source itself. It provides for the regulation of individual emission sources through performance standards that are based on what design or operational changes an individual source’s owner can integrate into its facility in order to reduce the rate of emissions from its operations. 1. The Text of Section 111. Section 111’s regulatory program is narrow. Under section 111(b), the EPA is to publish “a list of categories of stationary sources” that “cause[s], or contribute[s] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.”3 Once the EPA lists a source category, the Agency “establish[es] Federal standards of performance for new sources within such category.”4 Meanwhile, under section 111(d), the EPA is directed to “establish a procedure” under which “each state shall submit to the Administrator a plan which 3 4 CAA § 111(b)(1)(A). Id. § 111(b)(1)(B). 12 establishes standards of performance for any existing source for any air pollutant . . . to which a standard of performance under [section 111] would apply if such existing source were a new source.”5 The statute adopts the same definition of “standard of performance” for both new and existing sources: a “standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.”6 In addition, when adopting standards of performance for existing sources, the CAA directs states and the EPA to consider, “among other factors, the remaining useful life of the existing source to which such standard applies.”7 On its face, section 111 provides only for standards that regulate the emissions performance of individual stationary sources. The plain text of this section makes it clear that standards of performance apply to sources within listed categories and do not regulate categories or subcategories as a whole. Further, the CAA narrowly confines the stationary sources that may be regulated under section 111 to any individual “building, structure, facility, or installation which emits or may emit any air pollutant.”8 This definition notably does not extend to combinations of these facilities or to other non-emitting entities. In addition, section 111(d) explicitly directs states and the EPA to consider the “remaining useful life” of existing sources when applying any standard of performance, further demonstrating that this section focuses 5 Id. § 111(d)(1). Id. § 111(a)(1). 7 CAA § 111(d)(1)(B). 8 Id. § 111(a)(3). 6 13 solely on what individual sources can do to improve their performance at reasonable cost rather than what the entire source category (or even other entities) can do collectively to reduce overall emissions.9 Section 111 also requires that any standard of performance be “achievable” by the sources to which it applies based on application of an “adequately demonstrated” system of emission reduction.10 The achievability requirement clearly indicates that Congress intended standards of performance to be based on systems of emission reduction that are within the control of (and thus, incorporated into the design or operation of) an individual source. A standard cannot be “achievable” for a source if the source must rely on measures taken by some other entity that it does not control, or must simply not operate, in order to achieve the standard. This focus on measures incorporated into individual sources can be seen in other parts of section 111 as well. For example, section 111(h) authorizes the EPA to promulgate a design, equipment, work practice, or operational standard in cases where “it is not feasible to prescribe or enforce a standard of performance,” and defines exactly when Congress considered it “not feasible” to establish a standard of performance.11 One such situation is where the regulated pollutant “cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant.”12 This provision clearly equates a “standard of performance” with the use of a conveyance at the regulated source to capture and to control a portion of the source’s emissions. 2. Context of Section 111 Within the CAA. 9 CAA § 111(d)(1)(B), (d)(2). Id. § 111(a)(1). 11 Id. § 111(h)(1). 12 Id. § 111(h)(2)(A). 10 14 The CAA’s other provisions establishing emission standards for new and existing sources all focus solely on achieving reductions in the rate of emissions at individual sources and only confirm the narrow scope of what and how the EPA may regulate under section 111. Nothing in the remainder of the CAA authorizes the EPA to regulate emissions from stationary sources by basing standards of performance on measures that are not implemented by the regulated source itself. Likewise, there is no provision of the CAA under which the Agency may base a standard of performance on reduced operations. Standards of performance cannot be based on enforceable limitations on hours of operation or on production rate. 3. The History of the EPA’s Implementation of Section 111. Although the text of section 111 (read in the context of the overall statute) provides the framework for regulation under this section, the EPA’s long and consistent history of implementing section 111 confirms the plain language of the statute and has given shape to this regulatory program. The Agency’s past rulemakings reflect the program’s singular focus on individual sources. In fact, in the 44-year history of the Act, the EPA has limited the scope of section 111 of the CAA to the regulated source in every rulemaking it has undertaken. Out of the nearly 100 NSPS and emission guidelines the EPA has promulgated and subsequently revised since 1970, every single standard of performance has been based on a “system of emission reduction” that is incorporated into the design or operation of individual sources. With its over forty years of regulating EGUs under section 111, the EPA has never before even considered basing a standard of performance for emissions from these sources on reduced utilization or shifting generation to lower-emitting sources. Nor has the EPA’s focus on individual sources changed in recent years. In an NSPS rulemaking that took place just weeks 15 after the Proposed Guidelines were published, the EPA once again reaffirmed that standards of performance “apply to sources” and must be “based on the BSER achievable at that source.”13 Because of the nature of section 111(d), the EPA has conducted very few rulemakings under that provision. But on the few occasions the EPA has issued emission guidelines for existing sources, it has maintained the same focus on measures that the regulated source can incorporate into its design or otherwise implement by itself. Since 1970, the EPA has published valid emission guidelines under section 111(d) for only five source categories, and in all five of these rulemakings the emission guidelines were based on the application of pollution control technology or other process controls at individual sources.14 Even the EPA’s short-lived Clean Air Mercury Rule (“CAMR”) under section 111(d) did not adopt a broader approach to establishing standards of performance. Although the CAMR did authorize an emissions trading program as a tool for compliance with standards of performance, the “system of emission reduction” that was used to set the emission guidelines themselves was limited to pollution control technology that could be installed at individual sources.15 (Final guideline was “based on the level of Hg emissions reductions that will be achievable by the combined use of co-benefit (Clean Air Interstate Rule) and mercury-specific controls.”). In summary, the plain text of section 111 of the CAA establishes a program that is clearly focused on reducing the rate of emissions from new and existing stationary sources through the 13 79 Fed. Reg. 36,880, 36,885 (June 30, 2014). 41 Fed. Reg. 19,585 (May 12, 1976) (guidelines for phosphate fertilizer plants based on “spray cross-flow packed scrubbers”); 41 Fed. Reg. 48,706 (Nov. 4, 1976) (guidelines for sulfuric acid production units based on “fiber mist eliminators”); 43 Fed. Reg. 7597 (Feb. 23, 1978) (guidelines for kraft pulp mills based on various process controls and two-stage black liquor oxidation system); 45 Fed. Reg. 26,294 (April 17, 1980) (guidelines for primary aluminum plants based on “effective collection of emissions followed by efficient fluoride removal by dry scrubbers or by wet scrubbers”); 61 Fed. Reg. 9905, 9907 (Mar. 12, 1996) (guidelines for municipal solid waste landfills based on “(1) a well-designed and well-operated gas collection system and (2) a control device capable of reducing NMOC in the collected gas by 98 weight-percent”). 15 70 Fed. Reg. 28,606, 28,617-20, 28,621 (May 18, 2005). 14 16 application of systems that can be integrated into the design or operation of the source itself. The overall context of the CAA and the EPA’s constant application of this approach outside of the present rulemaking confirm this focus. B. The EPA’s Proposed Action in the Proposed Guidelines Deviates So Far from the CAA as to be Unrecognizable as an Exercise of Section 111 Authority. The broad program of energy resource management and economy-wide demand reduction the EPA has proposed to create and administer in the Proposed Guidelines bears no resemblance to the source-focused regulatory program that Congress established in section 111 and the EPA has consistently implemented over the past four decades. In the Proposed Guidelines, the Agency has defied precedent and logic by essentially rewriting some parts of the CAA and completely ignoring others. The EPA’s proposal would completely overturn the CAA’s regulatory process under section 111 for controlling emissions from existing sources, and nearly every aspect of the Proposed Guidelines is inconsistent with the CAA and with the EPA’s binding rules. In particular, the Agency’s redefinition of what measures may constitute a “system of emission reduction” is clearly impermissible in light of section 111’s exclusive focus on what individual sources can achieve and the past four decades of contrary implementation. Likewise, the EPA’s claim that it may apply its chosen BSER to a state as a whole rather than to individual sources in a source category lacks any legal merit. And, finally, the fact that the Proposed Guidelines’ required emission reductions cannot be enforced without dramatically expanding the universe of entities subject to obligations under section 111 far beyond the designated source category further underscores how far the EPA has deviated from the scope of permissible regulation. 1. The EPA’s Proposed Guidelines Impermissibly Base Standards of Performance on Measures that Go Beyond the Regulated Source Itself. 17 Perhaps the most fundamental departure from the law in the EPA’s Proposed Guidelines is the Agency’s assertion that the “best system of emission reduction” for the sources in a designated source category under section 111 may include measures that would (either directly or indirectly) reduce a source’s utilization or that are not within the control of individual sources. Of the four “Building Blocks” that make up the EPA’s proposed statewide BSER for existing EGUs, only Building Block 1 (heat rate improvements at coal-fired EGUs) falls within the scope of measures contemplated in the CAA and could therefore provide the foundation for a legally defensible emission guideline. The others—mandating redispatch of generation from coal-fired units to NGCC units, displacing generation from affected EGUs with generation from renewable energy sources, and reducing electricity demand through energy efficiency measures—all impermissibly rely on measures that go beyond the boundaries of individual affected EGUs and that are not within the control of individual EGU owners and operators. The measures in Building Blocks 2, 3, and 4 are all based on implementation of statewide energy policies that would confiscate the available production of existing coal-fired EGUs. The Proposed Guidelines go so far as to impose undefined regulatory obligations on a broad swath of unspecified “affected entities” in addition to the fossil fuel-fired EGUs that are the source category for this rule, many of which do not emit CO2 in any appreciable amount. This “beyond-the-source” approach would allow the EPA to restructure every aspect of the states’ electric power markets and regulate any electricity user——for the purposes of reducing demand for and generation by sources in the designated source category (i.e., existing fossil fuel-fired EGUs). This is plainly impermissible under the CAA. The origin of this claim to regulatory power lies in the Agency’s attempt to rewrite what constitutes a “system of emission reduction” for the purposes of section 111. As noted above, 18 under that section, a standard of performance must reflect the “degree of emission limitation achievable through the application of the best system of emission reduction” that has been adequately demonstrated for sources in the regulated category.16 For the first time in its more than 40 year implantation of the CAA, the EPA asserts that because the word “system” is not explicitly defined in the CAA, the Agency may freely apply that word’s abstract dictionary definition: “a set of things working together as parts of a mechanism or interconnecting network; a complex whole.”17 The EPA applies this definition in the abstract to conclude that a “system of emission reduction” can be “virtually any ‘set of things’ that reduce emissions,” including anything from “add-on controls . . . to measures that replace production or generation at the affected sources.”18 The Agency even claims that it may require “reduced utilization” of a source as part of a “system of emission reduction,” conceivably including a complete prohibition on utilizing any specific regulated source.19 The breadth of the EPA’s unprecedented assertion of authority is unreasonable, particularly in light of section 111’s singular focus on regulating individual sources of emissions. Under the EPA’s asserted definition of a “system of emission reduction,” standards of performance for sources in a regulated source category would become a mere pretext for imposing a wide range of demand-reducing obligations on countless entities across the entire nation. The EPA would be able to effectively require any “affected entity” to implement any “set of things” that the Agency believes would potentially have the effect of reducing the 16 CAA § 111(a)(1). Legal Memorandum for Proposed Carbon Pollution Emission Guidelines for Existing Electric Utility Generating Units (“EPA Legal Memorandum”) at 51, Docket No. EPA-HQ-OAR-2013-0602-0419. 18 Id. at 51-52. 19 Id. at 79; 79 Fed. Reg. at 34,889. 17 19 operation of sources in the designated source category—and hence emissions from that category—no matter how far removed the required actions are from the source itself. These beyond-the-source measures are inconsistent with the regulatory program Congress provided for in section 111 of the CAA. Although the dictionary definition of “system,” if considered in the abstract, might theoretically embrace statewide, regional, or even national reduction programs, we make clear in the above sections that the word as used in section 111 can refer only to reductions resulting from measures that are incorporated into the source itself. The EPA’s claim that nothing in the language or context of section 111 limits the Agency’s expansive redefinition of “system of emission reduction” is clearly false, and it suggests that the EPA has simply ignored the statute and its own past rulemakings.20 Section 111’s clear focus on measures that are achievable by the regulated source itself pervades every aspect of that provision’s language, its statutory context, and the EPA’s rulemakings implementing that provision. As noted above, section 111 requires that emission guidelines and standards of performance be “achievable” by “any existing source” in the regulated category—not by only some sources, or by the category in the aggregate. An emission guideline that requires regulated sources to obtain emission reductions “beyond-the-source” in order to comply with an otherwise unachievable standard would unambiguously violate the plain text of the CAA. Yet the EPA failed to acknowledge how the achievability requirement limits the systems of emission reduction that may provide the basis for section 111 regulation. Building Blocks 2, 3, and 4 of the proposed BSER require measures that go beyond individual existing EGUs, and therefore cannot support development of an achievable emission guideline. The owner of an individual 20 See EPA Legal Memorandum at 51-52. 20 coal-fired utility boiler cannot control the dispatch of NGCC units relative to other fossil fuelfired EGUs. Nor can it make changes in the design or operation of its boiler that would generate wind or solar renewable energy or that lead consumers to use less electricity. Section 111 could not be more clear that its standards of performance for new and existing sources must be achievable by individual sources using measures that are implemented into the sources themselves. When compared to the narrow regulatory program that Congress created in section 111 and that the EPA has given shape to through its consistent administrative implementation, the authority that the Agency now claims under its novel redefinition of “system of emission reduction” is unlawful. The EPA’s beyond-the-source approach would “bring about an enormous and transformative expansion in the EPA’s regulatory authority without clear congressional authorization”—indeed, despite clear congressional language and regulatory history contradicting that claim of authority.21 2. The EPA Cannot Consider Reduced Utilization of Regulated Sources as BSER. These same fundamental flaws extend to the EPA’s proposed “alternative approach to BSER,” under which BSER is, “in addition to [B]uilding [B]lock 1, the reduction of affected fossil fuel-fired EGUs’ mass emissions achievable through reductions in generation of specified amounts from those EGUs.”22 Under this approach, “the measures in [B]uilding [B]locks 2, 3, and 4 would not be components of the system of emission reduction but instead would serve as bases for quantifying the reduced generation (and therefore emissions) at affected EGUs, and assuring that . . . the reduced generation can be achieved while the demand for electricity 21 22 See UARG v. EPA, 134 S. Ct. at 2444. 79 Fed. Reg. at 34,889; EPA Legal Memorandum at 79. 21 services can continue to be met in a reliable and affordable manner.”23 The EPA has no authority to establish a standard of performance based on reduced utilization of a source. A standard of performance regulates a source’s emission performance—i.e., its maximum design emission rate—and not its total emissions of a pollutant. Any standard of performance under section 111 must be based on measures that can reduce an individual source’s rate of emissions. This is evident from the fact that Congress clearly distinguished between an “emission standard” or “emission limitation” and a “standard of performance.”24 In addition, section 111(a)(1) further specifies that a “standard of performance” for the purpose of section 111 must be a “standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of” BSER.25 Thus, the standard of performance must set forth the degree of emission limitation—i.e., the relative intensity or rate of emissions— for a source that is achievable by applying a system of emission reduction to that source. Further, the performance standard is a standard for “emissions of air pollutants,” and not one for operation of the source. There is no room in this language for a reading that Congress authorized the EPA to direct the operation of a particular source . The EPA has never proposed reduced utilization or operation of the source as a system of reduction under section 111—despite the fact that reducing utilization or operation of the source would always result in fewer overall emissions from the source simply because the source does not have any emissions during periods of non-operation. The required reductions in generation the EPA is contemplating under the alternative BSER approach would not improve the emission rate of affected EGUs, and thus cannot be the 23 Id. at 34,889. CAA § 302(k), (l). 25 Id. § 111(a)(1). 24 22 basis of a standard of performance. Limiting operations does not yield “continuous emission reduction.” It limits emissions only during times when a source is not running. Likewise, a standard of performance cannot be “achievable” if it could only be met by reducing utilization of the source. An emission standard that required reduced utilization of EGUs would constitute the unlawful confiscation of production from affected EGUs. The EPA’s references to other statutory provisions of the CAA that may require some sources to reduce operations, such as the national ambient air quality standards (“NAAQS”) program and the residual risk provisions of section 112, are misplaced. Those provisions are based on emission levels required to meet the requirements of public health and welfare, whereas Congress explicitly required that section 111’s technology-based standards of performance be achievable.26 Notably, the EPA has never before claimed this authority in a section 111 rulemaking. As with the other “beyond-thesource” measures the EPA attempts to impose in the Proposed Guidelines, the EPA has never even considered capping a source’s operations as part of a system of emission reduction in any of its previous new source performance standards (“NSPS”) or emission guideline rulemakings. Under the EPA’s alternative BSER proposal, the standard itself would be an operational limit, and sources would have no way to avoid becoming subject to that limit. Further, the EPA’s “alternative BSER” approach is flawed because it still relies on the beyond-the-source measures that constitute Building Blocks 2, 3, and 4 of its proposed BSER. Under the alternative BSER, the EPA relies on Building Blocks 2, 3, and 4 in order to “determine ... the amount of the generation reduction component of the BSER” that is achievable for affected EGUs, by assuming that the beyond-the-source measures supporting those Building 26 EPA Legal Memorandum at 81-82. 23 Blocks provide available means to ensure that energy demand will still be met.27 But the measures in Building Blocks 2, 3, and 4 are beyond the control of individual affected EGUs themselves, and therefore cannot result in a standard of performance achievable for individual sources. The measures in Building Blocks 2, 3, and 4 are legally irrelevant under section 111, whether they are included as components of BSER themselves or are simply a premise for finding that reduced operations are achievable. 3. The Proposed Guidelines Are Based on Measures that States and the EPA Cannot Enforce Against Regulated Sources. The EPA’s impermissible redefinition of a “system of emission reduction” is not the only problem with the Agency’s proposal. In its attempt to accommodate such a large expansion of regulatory authority, the Agency deviates even farther from the statute and its own past rulemakings in numerous other ways that highlight the unlawfulness of the Proposed Guidelines. For example, the EPA’s proposal would impose federally enforceable obligations on a broad, undefined class of “affected entities” beyond the regulated category of existing EGUs in order to accomplish the Agency’s policy goal of reducing CO2 emissions by reducing the operation of existing coal-fired EGUs. Yet nothing in the CAA authorizes the states or the EPA to impose obligations on any entity under section 111 other than a source in a listed source category, but the level of emission reductions contemplated by the EPA in its proposal cannot possibly be achieved through standards of performance that apply to existing EGUs alone. The aggregate emission reductions associated with Building Blocks 2, 3, and 4 cannot be expressed as part of a standard of performance that applies to regulated sources because they do not reduce the emission rate of individual EGUs and cannot be implemented by individual sources. The owner of an individual existing EGU cannot implement measures at that EGU that increase the share of 27 79 Fed. Reg. at 34,889. 24 a state’s overall fossil fuel-fired generation that is provided by NGCC units, increase generation from renewable energy sources, or measures that cause electricity consumers to use energy more efficiently. Furthermore, that owner cannot ensure that any efficiency improvements will actually lead to reduced energy consumption. Likewise, the EPA and states have no authority under section 111 to base a standard of performance on the reduced utilization of a source. At the same time, nothing in section 111 authorizes the EPA or the states to adopt legally enforceable obligations on other entities in order to achieve the aggregate emission reductions the EPA has concluded could be obtained under Building Blocks 2, 3, and 4. The statute could not be more clear that the only emission control obligations that it authorizes the EPA and states to impose are standards of performance that apply to new and existing sources in listed source categories. Section 111 provides that legal requirements will apply only to regulated sources themselves. Nowhere else in that section does Congress authorize the imposition of binding legal obligations for entities other than the regulated source, nor for that matter did Congress authorize the EPA to impose the compliance obligation on the states. Accordingly, only a very narrow set of entities may be subject to requirements under section 111(d). First, the entity must be a “stationary source,” meaning a “building, structure, facility, or installation which emits, or may emit any air pollutant.”28 Second, that stationary source must be an existing source that falls within a “category of sources” the EPA has listed as eligible for regulation because that category “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.”29 And finally, the EPA must have promulgated a standard of performance for new sources in that category that 28 29 CAA § 111(a)(3). Id. § 111(b)(1)(A). 25 applies to the relevant pollutant.30 If an entity is not a stationary source of pollutants in a category for which the Agency has promulgated an endangerment finding and an applicable NSPS, then that entity is free from any obligation under section 111(d). The statute clearly does not authorize the EPA to impose obligations on the types of entities that the Agency would need to regulate in order to implement the beyond-the-source measures underlying the Proposed Guidelines. Despite this fact, the Agency proposes to deviate from the regulatory program established in section 111 and direct states to impose legal obligations on “affected entities” in order to obtain the aggregate emission reductions that cannot be achieved by adopting proper standards of performance for existing EGUs.31 The EPA’s proposed definition of “affected entity” is circular and broad. It includes any “entity with obligations under this subpart for the purpose of meeting the emissions performance goal requirements in these emission guidelines.”32 In other words, under the EPA’s so-called “portfolio approach,” the Proposed Guidelines would allow a state to impose enforceable requirements upon any entity that the state believes could directly or indirectly reduce energy demand, and thus emissions, from existing fossil fuel-fired EGUs. By the EPA’s own admission, the standards of performance applicable to individual affected EGUs—i.e., the standards actually contemplated by section 111—“would not, on their own, assure, or be required to assure, achievement of the emission performance level” that is determined to represent the application of BSER to affected sources.33 Instead, “the state plan would include measures enforceable against other entities that support reduced generation by, and therefore CO2 emission reductions from, 30 Id. § 111(d)(1)(A)(ii). 79 Fed. Reg. at 34,901-03. 32 79 Fed. Reg. at 34,956, Proposed 40 C.F.R. § 60.5820. 33 79 Fed. Reg. at 34,901. 31 26 the affected EGUs.”34 These measures “would be federally enforceable because they would be included in the state plan.”35 The Agency suggests that affected entities could include “electric distribution utilit[ies],” “private or public third-party entit[ies],” or “a state agency, authority or entity.”36 There is virtually no limit on the types of “affected entities” the EPA or states might choose to regulate under section 111. The EPA’s attempt to authorize regulation of these “affected entities” under a program to establish performance standards for a source category of EGUs has no basis in the CAA. Much like the Agency’s novel redefinition of “system of emission reduction,” the EPA has never applied this “portfolio approach” in any of its previous NSPS or emission guideline rulemakings over the past four decades. The Agency’s primary argument for this departure is that “[t]here is no specific language in CAA section 111(d) or elsewhere in the CAA that prohibits states from including measures other than performance standards and implementation and enforcement measures” in state plans for existing sources.37 But this argument incorrectly assumes that, under the CAA, any action that Congress did not explicitly prohibit is permitted. In fact, just the opposite is true. Congress must “speak clearly if it wishes to assign to an agency decisions of vast ‘economic and political significance.’”38 A reading of the CAA that gives the EPA and states the authority to potentially impose obligations on any entity that uses electricity would unquestionably bear vast economic and political significance. As the EPA admits, “the terms of CAA section 111(d)(1) do not explicitly address whether, in addition to emission limits on affected EGUs, state plans may include other measures for achieving the emission performance 34 Id. Id. 36 Id. at 34,917. 37 79 Fed. Reg. at 34,903. 38 UARG, 134 S. Ct. at 2444. 35 27 level.”39 Without such explicit authorization, the EPA may not seize regulatory authority over affected entities beyond the affected sources on which section 111’s narrow regulatory program is focused. As the EPA also acknowledges, its proposal to include enforceable requirements for affected entities as part of the emission guidelines raises significant practical enforcement concerns that are not addressed in the Proposed Guidelines.40 In order to receive EPA approval, a state plan must contain “enforceable measures that reduce EGU CO2 emissions.”41 Once a state plan is approved by the Agency, its provisions—including its requirements for affected entities—would then generally become federally enforceable by the EPA and by private individuals in citizen suits.42 Yet it is unclear what kind of “enforceable” obligations a state could impose on affected entities in order to implement Building Blocks 2, 3, and 4, or how those requirements could be enforced in the event they are not implemented. Accordingly, it may well prove impossible for states to submit plans that are “approvable” under the EPA’s criteria. For example, the EPA suggests that in order to implement Building Blocks 2, 3, and 4, “affected entities” may include “a state agency, authority or entity,” such as a state environmental management agency or public utilities commission.43 In some states, these may be the only entities with authority to effectively implement the redispatch of generation from existing coal-fired units to NGCC units, or to coordinate investments in renewable energy 39 79 Fed. Reg. at 34,902. Id. at 34,909 (“A portfolio approach may result in enforceable state plan obligations accruing to a diverse range of affected entities beyond affected EGUs, and . . . there may be challenges to practically enforcing against some such entities in the event of noncompliance.”). 41 Id. 42 CAA §§ 113, 304(a). 43 79 Fed. Reg. at 34,917. 40 28 generation or demand-side energy efficiency campaigns. These state agencies are protected, however, from suit under the CAA’s citizen suit provision. Therefore, it would not be possible to enforce emission-reducing measures that result from state created plans and procedures and are the responsibility of state agencies. In that case, under the plain terms of the EPA’s proposal, the state’s plan submission would not be approvable unless the state adopts legislation expressly opening its agencies to citizen suits seeking to enforce these obligations, which would plainly exceed the scope of measures the EPA may require in a state plan. The EPA has not provided any details regarding the criteria that would be used to evaluate State Implementation Plans (“SIPs”) resulting from the Proposed Guidelines. Nor does the CAA or the EPA’s past rulemakings under section 111 provide insight. That is because the types of aggregate emission reduction measures and the broad universe of affected entities the EPA asserts authority over in the Proposed Guidelines are so far removed from section 111’s narrow source-focused regulatory program as to be unrecognizable. The CAA “do[es] not explicitly address” any of these issues for the same reason that section 111 does not explicitly address mobile source regulation or endangered species protection: because such language would be nonsensical in a statutory provision that has nothing to say about those issues. Section 111, on its face, is singularly concerned with implementing measures that reduce the maximum design emission rate at individual new and existing sources within specific categories of stationary sources. That the EPA is now grappling with the complex question of how to impose enforceable obligations on other affected entities that reduce aggregate emissions simply demonstrates that the EPA has strayed far off the CAA’s regulatory path. The extent to which the EPA has deviated from the statute is further evident from the fact that if a state does not submit an “approvable” plan, the EPA has no authority to promulgate a 29 federal plan that includes the measures it would require of states. In order to be approvable, the EPA proposes that states must accomplish the impossible task of including enforceable measures in their state plans that achieve emission reduction targets that are simply not achievable or enforceable. To the extent that states are unable to adopt “enforceable” requirements implementing the EPA’s beyond-the-source approach, the EPA will face the prospect of developing federal plans for those states. Once the EPA assumes responsibility for developing a plan for a state’s existing EGUs, however, it would lack the authority necessary to implement the beyond-the-source measures contemplated under Building Blocks 2, 3, and 4. The EPA cannot adopt a plan that imposes a federally enforceable energy resource development and dispatch program upon states. The Agency has no authority over independent system operators, state public utility commissions, or other entities responsible for managing the dispatch of EGUs to meet load requirements. Indeed, even under section 110 of the CAA—a provision that gives the states and the EPA much broader authority to require aggregate emission reductions from diverse sources than does section 111— the EPA has no power under a federal implementation plan to impose legally enforceable obligations on entities other than stationary sources of emissions. And importantly, section 111 gives the EPA no authority to base a standard of performance on reduced utilization or operation of a source. In summary, section 111 of the CAA creates a narrow regulatory program in which the EPA—or in the case of section 111(d), states—adopts standards of performance for stationary emission sources in specified categories that reduce each source’s maximum rate of emissions based on the implementation of achievable measures that can be incorporated into the design or operation of the source itself. The EPA has consistently applied the program in this manner for 30 over forty years. By contrast, the Proposed Guidelines require states to enact measures that reduce aggregate emissions from each state’s fleet of existing EGUs overall, based on measures that are beyond the control of individual EGUs and that can be achieved only by imposing obligations on other “entities” the state identifies that produce or consume electricity or by requiring existing EGUs to simply curtail operations altogether. The contrast could not be more clear. The EPA’s Proposed Guidelines are inconsistent with the design and structure of the statute as a whole, and must be withdrawn and reissued to conform with the CAA. C. The EPA’s Section 111(d) Proposed Guidelines Are Inconsistent With the Agency’s Section 111(b) Proposal. The EPA’s section 111(b) proposal for modified and reconstructed sources44 is in conflict with the Agency’s section 111(d) Proposed Guidelines. Generally speaking, the strictness of the NSPS progresses with the strictest limit reserved for wholly new facilities that can build in the design needed to meet mandated emission rate standards before being built. The next and lesser strict standard applies to reconstructed units, those units that without respect to emissions impacts are undertaking such a significant rebuild (50 percent or more) that requiring retrofitting new controls and designs to achieve lower emissions is economically justified. The next level of standard applies to those units that are modified to increase net emissions above significance thresholds. By undertaking these changes, the units subject themselves to the same sort of economic retrofit standard as reconstructed units. The least strict standards are applied to existing units that have undertaken neither a modification nor a reconstruction. Because these units continue to operate as designed, the burden of installing new designs and controls to 44 79 Fed. Reg. at 34,960. 31 achieve lower emissions is the hardest to justify.45 This is how the EPA has historically applied NSPS and new source review (“NSR”) to emitting sources. But the EPA now turns that program on its head, most evident when comparing the proposed requirements under the section 111(b) and the Proposed Guidelines under section 111(d). Where one would expect to see the most stringent limits on brand new, yet-to-be-constructed sources, in fact the lowest, most stringent limits are proposed to be applied to existing units under section 111(d), where existing utility boilers in states such as North Carolina or South Carolina will have to meet emission rates of 992 and 772 pounds per net megawatt hour (“lbs./MWh-net”) of CO2, respectively. Yet utility boilers yet to be constructed must meet only a rate of 1,110 lbs./MWh-net of CO2, and that with carbon capture and sequestration. Modified or reconstructed units would have to meet a maximum emission rate of 1,900 lbs./MWh-net of CO2. In its section 111(b) proposal the EPA states: Because a reconstruction generally entails rebuilding the unit, operating practices and equipment upgrades are not applicable as BSER. Those entail smaller scale changes to the unit that may be expected to be rebuilt anyway. In addition, the emission reductions that would be achieved through best operating practices and equipment upgrades are smaller than the most efficient generation technology.46 In these three sentences, the EPA states that rebuilding with the most efficient technology should be BSER for an affected unit (and yet it proposes an emission rate of 1,900 lbs./MWh-net ofCO2), and admits that even smaller emission reductions are the best that can be hoped for with best operating practices and equipment upgrades. Yet the least stringent emission rate proposed by the EPA under section 111(d) is less than 1,800/MWh-net of CO2. 45 46 See Fla. Stat. § 403.021(7)(d). 79 FR 34984 (2014). 32 Even more telling is that modified or reconstructed units would have to achieve efficiency improvements of 2 percent, while an existing utility boiler making no change would have to achieve an initial 6 percent improvement, as proposed by EPA in Block 1 of the agency’s preferred option. The EPA offers no reliable data to support the achievability of either a 2 percent or 6 percent improvement and provides no information regarding the durability of such an improvement. Many efficiency improvement measures begin to degrade as soon as they become operational. Thus, CO2 reductions from efficiency improvement projects are real, but fleeting and cannot be counted on to provide lasting reductions. The EPA admits in its section 111(b) proposal that the most improvement an existing utility boiler can reasonably make is a 2 percent improvement, thereby undercutting the justification in its section 111(d) proposal for an initial 6 percent improvement for existing utility boilers. Another more puzzling part of the EPA’s proposal is that a boiler may be subject to both section 111(d) and section 111(b). This arises solely from the EPA’s elaborate section 111(d) proposal. Under any other NSPS, a modified source would be required to meet a standard equal to or more stringent than an existing source. So no question arises about whether an existing source affected under NSPS guidelines must continue meeting those guidelines once it triggers section 111(b) as a modified source. However, by establishing a more stringent standard for covered existing units, the EPA must develop some rationale for continuing to subject an existing unit to the more stringent existing source standard even when it modifies the unit and triggers application of the lesser section 111(b) standard. All of these regulatory contortions are avoided if the EPA proposed a reasonable section 111(d) standard. In effect, the EPA proposes two different “best system of emission reduction standards” and attempts to apply them 33 simultaneously to the same unit. This part of the proposal is arbitrary, capricious, and exceeds the legal limits of the EPA’s authority. The EPA cites K Mart Corp. v. Cartier, Inc., 486 U.S. 281 (1988) to support its approach of creating two separate systems of BSER and applying them to the same units simultaneously. However, K Mart is not a CAA case, and the fact that the best authority the EPA could find to justify its proposal is an unrelated case about trademarks and gray goods is a telling indication that this proposal is unprecedented and that the EPA has overstepped the bounds of its authority. D. The EPA’s Proposed Guidelines Are Unconstitutional. The EPA’s Proposed Guidelines violate the Tenth Amendment to the Constitution. National League of Cities v. Usery, 426 U.S. 833 (1976) held that the federal government cannot directly displace the states’ freedom in areas of traditional governmental functions. The EPA’s proposal under section 111(d) does precisely that. It creates and imposes no federal NSPS. Rather it creates 50 different standards, each one unique to an individual state. Each is built upon the prior sovereign decisions exercised by each state in the areas of electric resource planning. The Proposed Guidelines take these state choices and then builds upon them by imposing reduction requirements premised largely on matters under sovereign state control such as how many hours specific types of operating units will run, what plants retire, and the development of renewable energy sources. The EPA cannot pretend to have authority over nuclear plants or implementation of renewable standards, but it nevertheless directs individual states to meet emission rates designed by the EPA for that state alone and premised on assumptions within the realm of state sovereignty. The EPA’s proposal clearly regulates the “states as states” and falls clearly within Nat’l League of Cities. There are three showings that must be made to demonstrate a violation of the Tenth Amendment under Nat’l League of Cities. 34 First, there must be a showing that the challenged statute regulates the states as states. Second, the federal regulation must address matters that are indisputably “attributes of sovereignty” . . .. And third, it must be apparent that the states' compliance with the federal law would directly impair their ability “to structure integral operations in areas of traditional functions.”47 As explained in Hodel v. Virginia Surface Mining & Reclamation Association, Inc., 452 U.S 264 (1981), a federal requirement that compels a state to enforce the federal requirement and expend state funds or “participate in the federal regulatory program” intrudes upon the sovereign state.48 It is no answer that the EPA might be able to require similar actions if done a different way; it is the specific requirements of the proposal in the way they are both developed and enforced that are unconstitutional. If the EPA can effect a similar outcome using another means, then it must use that other means. The EPA’s proposal intrudes upon the policy choices of states in areas of which they have traditionally exercised sovereignty. The EPA’s proposal fails to consider independent state law that obligates public utilities to meet customer demand. For example, North Carolina requires, via legislation empowering the Utilities Commission, that regulated utilities operate their systems, and dispatch their units, in a manner which meets customer demand at the least cost, while maintaining reliable service. The legislature and Utilities Commission have concluded, as a matter of policy, that least cost reliable electricity is their goal. Likewise, many states have already made policy decisions about the appropriate application of renewable energy or energy efficiency within the borders of their states. The clearest example of this is Kentucky, 47 Hodel v. Virginia Surface Mining & Reclamation Association, Inc., 452 U.S 264, at 288. 48 Id. 35 which specifically defeated a legislative proposal mandating renewable energy49 and recently enacted legislation espousing a policy against prescriptive emissions standards that dictate the makeup and operation of electric generation.50 The Kentucky statute, adopted on July 15, 2014, would prevent implementation of the Proposed Guidelines via the Building Blocks and essentially assures that the 111(d) proposal could not be implemented at all. South Carolina’s statute 48-1-30 calls into question whether the South Carolina Department of Health & Environmental Control could impose the sort of limits needed via the Building Block BSER approach. E. The EPA Has Not Demonstrated That its Proposed BSER Has Been Adequately Demonstrated. The EPA’s proposed BSER is flawed for a fundamental reason. The EPA is required to show that its BSER has been adequately demonstrated. However, the EPA has not even attempted to do so. The EPA has proposed a series of four disparate Building Blocks, each of which may have been achieved somewhere in some form similar to that described, but have not been used together. The Agency’s proposed BSER, however, is not any individual Building Block. Rather it is all four blocks working together simultaneously, and this is what the EPA describes as its “system,” and therefore what the EPA must demonstrate has been accomplished before it can call the four Building Blocks BSER. But the EPA has not attempted to show any example in the United States or anywhere in the world for that matter where such a coordinated system of these four Building Blocks has been demonstrated to work together. Likewise, the EPA fails to provide any reference to any regulatory system imposing emission rates such as those they derive from their proposed BSER. 49 50 KY H.B. 170, Bill Text (2013). Ky. Rev. Stat. Ann. §224.20-142. 36 Setting aside for the moment the capriciousness of developing so many different emission rates for the same pollutant from the same sources, something that EPA has not previously attempted, the EPA cannot show where a government has imposed net output based emission rates of 378 (Maine) and 740 (Florida) lbs./MWh-net of CO2. Even the highest state goal, 1,778 (North Dakota) lbs./MWh-net of CO2 is lower than the section 111(b) proposal for reconstructed and modified sources. The EPA has proposed a state-by-state emission rate for CO2, which is a standard that cannot be monitored for compliance during operation. No existing source could determine its current compliance status, because the compliance depends on numerous other factors, some of which are beyond anyone’s control. The NSPS for conventional pollutants is a pounds per hour rate and is determined by a stack test at the source, but a stack test at one source, at a given hour on a particular day provides no information about the operation of other sources at that same moment in time. When one considers that a state may dole out emission rate limits, and possible other operational limits, in an effort to reach an end-of-year rate balance, it soon becomes clear that the EPA is imposing a requirement on the state itself. This proposal is not an emission standard for affected sources. Rather it is a standard for each state. In fact, it treats nearly identical sources in different states very differently. Rather than creating a standard for the NSPS regulated source, the EPA is creating a standard for the states, but the states are not sources under the CAA or EPA regulations. States are not listed in 40 CFR Part 60. Moreover, the EPA’s unequal and inequitable treatment of states vis-à-vis one another and sources within different states demonstrates the patent arbitrariness of the EPA’s proposal and another reason why it is unconstitutional. 37 The EPA has created de facto source subcategories by state, but there is no legal basis for this. In its concurrent section 111(b) proposal the EPA states: Once the EPA has determined that a particular system or technology represents BSER, the EPA must establish an emission standard based on that technology.51 Even if the EPA’s 4-Building Block approach were lawful, establishing 50 different emission rates is not only unprecedented, but also it proves that the EPA has failed to determine a system that establishes an emission rate. While the Building Block approach has flaws of its own, these flaws are magnified by failing to apply the “particular system” uniformly. The Building Blocks get applied in whole or in part not because of any aspect of the affected sources the EPA is authorized to regulate under the CAA, but because of the current makeup of both regulated and non-regulated electricity producing and conserving facilities within a particular state. III. The EPA Cannot Regulate EGUs Simultaneously Under Sections 111(b) and 111(d) of the CAA. The EPA has proposed regulating existing sources that modify or reconstruct under both the existing source and new source provisions of section 111. In the proposed standards for modified and reconstructed EGUs, the EPA asserts that “existing sources that are subject to requirements under an approved CAA section 111(d) plan would remain subject to those requirements after undertaking a modification or reconstruction.”52 Likewise, in the Proposed Guidelines for existing EGUs under section 111(d), the EPA states that under its proposed interpretation “a modified or reconstructed source would be subject to both (1) the CAA section 111(d) requirements that it had previously been subject to and (2) the modified source or reconstructed source standard being promulgated under CAA section 111(b) simultaneously with 51 52 79 Fed. Red. At 34,987. 79 Fed. Reg. at 34,974. 38 this rulemaking.53 The EPA claims that it can adopt this position because section 111 is “silent on whether requirements imposed under a CAA section 111(d) plan continue for a source that ceases to be an existing source because it modifies or reconstructs.”54 This is incorrect. Section 111(a)(2) of the CAA states that “[t]he term ‘new source’ means any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.”55 Section 111(a)(6) states that “[t]he term ‘existing source’ means any stationary source other than a new source.” These definitions, by their own terms, are mutually exclusive. The critical fact here is that once a modification or reconstruction commences, the “existing” source ceases to exist and a “new” source emerges. New sources are subject to regulation pursuant to section 111(b). Section 111(d) cannot apply to sources subject to section 111(b). The EPA proposes for the first time to find statutory ambiguity in these provisions. In the Proposed Guidelines, the Agency sets forth two policy reasons to justify its proposed decision to subject new sources to both existing and new source regulatory requirements. First, the EPA claims that modified or reconstructed units should remain subject to the existing source program because “[u]ncertainty about whether units would remain in the program could be very disruptive to the operation of the program.”56 Second, the EPA argues that it should continue to apply the existing source program to modified and reconstructed sources because “potential discrepancies in the stringency of the two 53 79 Fed. Reg. at 34,903. Id. at 34,904. 55 CAA § 111(a)(2). 56 79 Fed. Reg. at 34,904. 54 39 programs” might “creat[e] incentives for sources to seek to avoid their obligations under a CAA section 111(d) plan by undertaking modifications.”57 Both of the EPA’s concerns would be resolved by withdrawing the proposed standards for modified and reconstructed EGUs. The EPA has discretion not to impose NSPS for modified or reconstructed units and by choosing not to do so in this instance, it would avoid the concern it has raised. State plans devised with the correct statutory interpretation in mind can include provisions to accommodate such changes. Indeed, the EPA envisions many sources shutting down as a result of the Proposed Guidelines.58 If state plans can accommodate units leaving the program through cessation of operations, there is no reason why they cannot accommodate the transition of modified or reconstructed units from the existing source program to the section 111(b) program for new sources. In addition, to the extent the EPA has designed a section 111(d) program that cannot function while adhering to the requirements of section 111(a)(2) and section 111(a)(6), it is the EPA’s proposal, not the CAA, that must be revised. With regard to the EPA’s concern that there could be an incentive for sources to modify or reconstruct “to avoid their obligation under a CAA section 111(d) plan,”59 for the reasons explained above, a source that undertakes a modification or undergoes reconstruction after the date of the proposal of the applicable NSPS has no obligation under a section 111(d) plan; it could only have such obligation as a matter of state law at the state’s discretion. The EPA cannot require the states to regulate a unit as both a new and existing source. To the extent the EPA has proposed discrepancies in the new source and existing source programs that might create incentives the Agency dislikes, the solution is not rewriting the terms of the CAA. 57 Id. RIA at 3-34, Table 3-12. 59 79 Fed. Reg. at 34,904. 58 40 The EPA’s proposed interpretation of the CAA is inconsistent with the statutory text of sections 111(a)(2) and 111(a)(6) and is unsupported by rational policy considerations. The EPA must, therefore, revise the Proposed Guidelines to conform to the CAA requirement that new sources subject to section 111(b) requirements cannot also be required to comply with section 111(d) state plans under the CAA. IV. State Implementation Issues. A. Despite the EPA’s Claims, States Have Little to No Flexibility in Their Ability to Meet the Proposed State Goals. In calculating the state goals, the EPA applied all four Building Blocks to each state’s 2012 electric generation to determine the extent to which the state could reduce its CO2 emissions rate by 2030.60 The EPA says that it will consider adjusting state goals if a state comments that one of the Building Blocks is technically infeasible or its costs “were significantly higher than that projected by EPA.” This implicitly acknowledges that the Agency adopted a one-size-fits-all approach to establishing state-specific goals without adequately considering individual state characteristics.61 However, the EPA also states that because it believes it is imposing “reasonable” levels of each Building Block (“rather than the maximum”) a state should be able to increase its use of another Building Block to compensate for a limited (or lack of) use of another Building Block.62 This overlooks the fact that not all measures are mathematically equivalent in terms of their resulting emissions reductions.63 Section 111(d) provides that states are to develop performance standards for individual sources as part of state plans, after considering state and local factors unique to individual 60 79 Fed. Reg. at 34,863. Id. at 34,893. 62 Id. 63 See section XVIII.B. of these comments for a further discussion of the disparate impacts of Building Blocks 3 and 4 across states. 61 41 emitting units, including the remaining useful life of individual units. The Proposed Guidelines are unlawful because the EPA is establishing the emission goals rather than allowing the states to do so, noting in the process that states have no authority to modify. Even if the EPA had authority to establish emission standards for the states, because the EPA has simply assumed each Building Block can be implemented fully without ascertaining whether that is in fact the case, the flexibility the EPA claims to be providing is, in fact, illusory. In many cases, states cannot realistically implement one or more Building Blocks at the level the EPA has assumed and they do not have the flexibility to increase the stringency of other Building Blocks or measures to achieve their mandated goals because contrary to the EPA claims, the level of stringency assumed by the EPA for each Building Block is, in many cases, unrealistic and unachievable. This leaves the retirement of coal-fired EGUs as one of the only options available to achieve the goals the EPA has proposed. A standard that forces this outcome cannot be described as flexible. B. The Interim Compliance Period Should be Eliminated to Provide States With More Flexibility, Avoid Reliability Problems, and Provide a Reasonable Period of Time to Comply. The proposed interim compliance period, which begins in 2020 and ends in 2029, does not provide adequate time for compliance planning and implementation to avoid reliability problems, severely limits state flexibility, and would have the effect of causing sub-optimal planning decisions as compared to merely having a 2030 final goal. If the interim compliance period and resulting lack of flexibility drives a large amount of coal unit retirements by 2020, significant time is required to complete the planning, approval and implementation for replacement generation; upgraded and expanded transmission and distribution facilities; and new natural gas pipeline infrastructure that will be required to support the retirements while maintaining system reliability. These changes will take years to plan and execute as they must 42 be carefully implemented so as not to cause reliability problems and to minimize cost impacts to consumers. They simply cannot be accomplished before 2020, the start of the interim compliance period. In its October 30, 2014 Notice of Data Availability (“NODA”), the EPA seems to recognize for the first time that the Proposed Guidelines’ interim goals deny states the implementation flexibility and safeguards for reliability that the CAA requires. This result is the opposite of what the EPA states it intended to preserve in the Proposed Guidelines.64 The Agency claims that its intent in proposing to require compliance with an interim goal is to “provide states with a reasonable glide path to compliance with their final goals by 2030.”65 Yet the EPA fails to explain why interim goals are necessary to achieve the Proposed Guidelines’ ultimate goal. 1. Many State Interim Goals Are Front-Loaded. One of the many problems with the interim compliance period is the fact that the EPA has front-loaded the emission reduction goals by assuming that Building Blocks 1 and 2 are fully implemented by 2020, and remain at that level throughout the 10-year interim compliance period. Adding to this problem is the fact that the 2020 goals also reflect an increase in renewable energy generation and demand-side energy efficiency over the 2012 baseline, thus further lowering the 2020 state goals. The consequence is that EPA is proposing that many states be required to achieve unrealistic CO2 emission reductions immediately. While under the Proposed Guidelines a state technically would not be required to fully achieve its 2020 interim goal, the more delay there is in meeting the front-end goals, the more 64 65 79 Fed. Reg. at 64,545. Id. at 64,548. 43 aggressive the back end of the program would have to be for a state to be able to meet its 10-year average interim compliance goal. There will therefore be significant adverse consequences for a state that does not meet its 2020 goal. In other words, given the significant reductions required of many states in 2020, states will not have the option of starting slowly and working up to the final 2030 goal on their own pace given the requirement that they must meet their average 20202029 interim goal. In fact, if a state were to fail in the early years of the interim compliance period to achieve its goals, it would have to actually exceed its final 2030 goal in the later part of the 2020-2029 interim period just to meet its 2020-2029 average interim goal. This means that a state could achieve a rate lower than its final 2030 goal in 2029, for example, yet still possibly be out of compliance because it may not have met its 10-year average interim compliance goal. Therefore, rather than having a 10-year ramp-up period to the 2030 goals and providing states with flexibility in the design of their plans, the interim compliance period creates a 2020 compliance cliff for many states. Given the fact that the measures required to achieve the 2020 goals cannot be implemented in many states by 2020, the 2020 goals for many states are simply unachievable.66 The over-aggressiveness of the proposed 2020 interim goal is illustrated by the EPA’s proposed goals for Florida and North Carolina. The 2020 goals for Florida and North Carolina account for 76 percent and 71 percent, respectively, of the total emission rate reduction requirement in 2030 relative to each state’s 2012 baseline. For each state, the majority of the 2020 reduction requirement is attributable to Building Blocks 1 and 2. Setting a state’s 2020 goal at a level that requires such a large percentage of a state’s final 2030 goal is unreasonable 66 The fact that the requirement is unattainable precludes it from qualifying as BSER. 44 and unachievable, especially given the exceedingly short time between state plan submittal and approval by the EPA, and 2020. 2. The Proposed Schedule Leaves Insufficient Time Between Approval of State Plans and 2020, the Start of the Interim Compliance Period. The interim compliance period presents a significant problem with respect to compliance because of the extremely compressed amount of time between when state plans are scheduled to be completed and approved by the EPA and 2020, the proposed start of the interim compliance period. Based on the EPA’s proposed plan submittal schedule, states can submit their plans to the EPA as late as June 2018 if they participate in a multi-state program. While it is too early to know what approach states will take with respect to their plan development, given the fact that the EPA is encouraging states to avail themselves of the option of working together to implement the program, the implementation schedule must be set based on the assumption that states will take the multi-state approach and therefore will not submit their plans until June 2018.67 As a result, the EPA would not approve state plans until mid-2019, just six months before the start of the interim compliance period, which is clearly unworkable. In the Proposed Guidelines, the Agency assumes that Building Blocks 1 and 2 will be fully implemented by 2020, but provides no evidence that states can actually do so. There is a significant void between the EPA’s assumptions and the reality regarding states and affected entities’ ability to meet the interim goals on the schedule the EPA has proposed. The 2020 start date for the interim compliance period simply leaves inadequate time after state plan submittal and approval for affected entities to develop compliance plans, have them approved, and implement those plans. As discussed in section V of these comments, the EPA’s assumed 6 percent heat rate improvement for existing coal-fired EGUs in Building Block 1 is unachievable for numerous 67 See section XVIII.D. of these comments for a discussion of the proposed SIP submittal schedule. 45 reasons unrelated to the implementation schedule for Building Block 1.68 However, because the 2020 interim state goals reflect full implementation of Building Block 1, states and affected entities will be forced to look elsewhere for reductions in 2020 to make up for the Building Block 1 shortfall. This only exacerbates the problems presented by the interim compliance period and the 2020 goals in particular, because there is not ample time to identify and achieve the extra reductions from other measures. As discussed in Section VI of these comments regarding Building Block 2, which the EPA has also assumed is fully implemented by 2020, the 70 percent capacity factor the EPA assumed for all existing and under construction NGCC units is actually more like 80 percent or higher because the EPA based its calculations on nameplate capacity rather than net rated capacity. Therefore, it’s unlikely that existing and under construction NGCC units would be able to ramp up operations in 2020 to fill the gap left by Building Block 1 to this level of continuous operation, let alone achieve the capacity factor the EPA assumed in Building Block 2.69 Being unable to achieve either Building Block 1 or 2 by 2020, states would have to look elsewhere to make up the difference. Yet, it is highly unlikely that many states could get more out of Building Blocks 3 and 4 than the EPA has already assumed in the state goals for 2020, again due to the limited time between state plan submittal and approval and 2020. There is also insufficient time to look beyond the Building Blocks to identify and implement other potential CO2 emission reduction opportunities to make up the shortfall. There are few if any options beyond those the EPA used as the basis for its BSER determination to further reduce CO2 emissions that could be implemented in the timeframe 68 Even if the proposed schedule provided adequate time to plan, design and implement heat rate improvements, 6 percent is a technically unachievable level of improvement. 69 The full implementation of Building Block 2 could require by 2020 in many states a substantial additional build out of transmission infrastructure and natural gas pipeline capacity and the EPA has failed to even demonstrate that the full implementation of Building Block 2 is achievable by 2020. 46 required by the interim compliance period. Therefore, the EPA’s decision to frontload emissions reductions for many states will likely result in the failure of states to meet their interim compliance period average goal. Regulated electric utilities have a legal duty to make reasonable and prudent investments pursuant to the review of their public utility commissions. Regulated utilities generally need prior commission approval before pursuing new projects such as new generation, demand-side energy efficiency, and major transmission projects. For projects needed to comply with the requirements of a state section 111(d) plan, utilities typically will not seek commission approval, nor would commission approval likely be given prior to the EPA approving a state plan because there is too much uncertainty about the final regulatory requirements for utilities or utility commissions to act before plan approval. In addition, once the EPA approves a state plan, it can take years for the utility to complete the necessary planning, receive the required permits and approvals for and implement the needed projects. Therefore, the EPA’s assumption that states can take significant steps to reduce emissions in advance of the start of the interim compliance period is incorrect. The proposed implementation schedule does not take this reality into account, but it must. 3. The Interim Compliance Period Will Create Substantial Stranded Investment. The compliance cliff imposed by the interim compliance period will likely have many adverse impacts, including creating substantial stranded investment from the premature shutdown of many existing coal-fired EGUs that could be forced to stop operating by 2020 given the front-loading of Building Blocks 1 and 2 and the steep reduction in the CO2 emissions required at the start of the interim compliance program. The EPA’s own analysis of the Proposed Guidelines predicts that 46 to 49 gigawatts (“GW”) of coal-fueled generation will be 47 shut down by no later than 2020 as a result of implementing the Proposed Guidelines.70 Forcing the premature shutdown of existing coal-fired EGUs by 2020 will result in billions of dollars in stranded assets as many of the units likely to be shut down will not otherwise be close to the end of their useful lives and, in many cases, units have recently installed, or are in the process of installing expensive pollution control equipment to comply with other EPA or state regulations. This means that consumers would have to pay for the same electricity generating stations twice: first the billions of dollars they are already paying or will be paying for the pollution controls that were previously installed or are being installed, and then for the replacement capacity that will be required.71 Such an outcome is both unnecessary and unacceptable, and can be avoided by eliminating the interim compliance period. 4. The Interim Compliance Period Could Create System Reliability Problems and Uneconomic Compliance Decisions. The interim compliance period is likely to result in reliability problems and uneconomic compliance decisions due to the short period of time available to develop and implement compliance plans. For example, there will likely be situations where the most economic decision for a company would be to retire certain coal-fired units as part of its compliance plan to meet the interim goals. However, if the units are located such that their continued operation is critical to maintaining system reliability, and because there is not enough time to design, permit, and implement the transmission upgrades and build replacement capacity necessary to allow the units 70 Based on the EPA’s incorrect projections for coal unit retirements associated with its MATS rule, we anticipate that the amount of coal-fired EGUs likely to be retired by 2020 could be substantially more than the Agency’s 46 to 49 GW estimate. 71 Retired coal-fired generating capacity must be replaced to maintain appropriate system reserve margins and system reliability. 48 to be shut down, 72 they would be forced to continue operating the units and the company would have to make the more costly decision to shut down other units instead, if such an option is even available. In addition, it is possible that actions required to meet the interim compliance targets would exceed what is required to meet the final 2030 targets, thus resulting in more costly compliance than just meeting the 2030 target without the interim compliance targets. From an overall power system perspective, the 46 to 49 GW of coal-fired generating units the EPA’s own analysis indicates will close before 2020 as a result of the interim compliance period, along with the additional approximately 70 GW of already announced coalfired unit closures by 2022 mean that almost a third of the coal-fired generating capacity available to meet demand in 2010 could be shut down by 2020. This can have significant reliability implications if not properly managed. Yet the interim compliance period would deprive states and utilities of the ability to effectively manage this transition in a way that ensures reliability and mitigates cost impacts. In November 2014, the North American Electric Reliability Corporation (”NERC”) released a report titled “Potential Reliability Impacts of EPA’s Proposed Clean Power Plan.” In its report, the NERC stated that “[T]he preliminary review of the proposed rule, assumptions, and transition identified that detailed and thorough analysis will be required to demonstrate that the proposed rule and assumptions are feasible and can be resolved consistent with the requirements of BPS reliability.”73 (Emphasis added.) The NERC goes on to state that “[S]tate and regional plans must be approved by the EPA, which is anticipated to require up to one year, leaving as little as six months to two years to implement the approved plan. Areas that 72 As discussed in Section XV of these comments, it could take seven years or more to complete construction of a new transmission line. 73 North American Electric Reliability Corporation “Potential Reliability Impacts of EPA’s Proposed Clean Power Plan,” November , 2014 at 1. 49 experience a large shift in their resource mix are expected to require both electric and natural gas transmission enhancements to maintain reliability. Constructing the resource additions, as well as the expected transmission enhancements, may represent a significant reliability challenge given the constrained time period for implementation.”74 (Emphases added.) Finally, the NERC states that “[I]f the environmental goals are to be achieved, policy makers and the EPA should consider a more timely approach that addresses BPS reliability concerns and infrastructure deployments.75 (Emphasis added.) It seems abundantly clear from the NERC report that implementation of the Proposed Guidelines could present reliability problems for the bulk power system, especially given the extremely compressed implementation schedule that has the interim compliance period beginning in 2020, possibly as little as 6 months after the EPA would approve state plans. Therefore, it seems prudent to expect that the retention of the interim compliance period, as proposed, will create reliability problems. The prudent path forward, therefore, would be to eliminate the interim compliance period. This will provide the time needed to develop compliance strategies, identify reliability problems, design needed reliability fixes, receive the necessary state approvals, and implement the compliance strategy, including needed reliability fixes, in support of meeting the 2030 goals. As further evidence that the proposed interim compliance period will result in electric system reliability problems and should be eliminated, the Midcontinent Independent System Operator, Inc. (MISO), in comments submitted to the EPA,76 state that “The interim emissions performance requirements create an untenable and infeasible timeline for reliable compliance, 74 Id. at 2. Id. at 3. 76 Letter from MISO to The Honorable Gina McCarthy, November 25, 2014. 75 50 and would cause MISO member companies to make decisions on a severely truncated timeline.”77 The letter goes on to state that “MISO urges EPA to remove the 2020-2029 interim emission performance period and levels from the final rule to allow sufficient time for reliable and efficient implementation of compliance strategies.”78 5. The EPA Has Discretion in Setting Compliance Schedules Under Section 111(d). The EPA and states have considerable discretion in setting appropriate compliance deadlines for meeting the CO2 performance standards that states must establish under section 111(d) of the CAA. The statute does not prescribe any specific deadline for compliance with applicable performance standards. Similarly, the Agency’s implementing regulations do not impose any specific compliance deadline. As discussed above, the timeline the EPA has proposed, with the interim compliance period beginning in 2020, provides no flexibility to states on the timing for implementation of Building Blocks 1 and 2. This inflexibility creates very significant and likely insurmountable challenges for many states that face very substantial CO2 emissions reduction requirements in 2020 due to the EPA’s assumption that Building Blocks 1 and 2 are fully implemented by 2020. If the EPA continues to pursue the overreaching policy reflected in its Proposed Guidelines, to correct the many problems that will be caused by the interim compliance period and ensure sufficient flexibility for the implementation of the stringent reduction obligations the EPA has proposed for 2030, the EPA should eliminate the interim compliance period and instead only require states to achieve their final emission rate goals in 2030. Under this approach, each state would have the responsibility of developing its own glide path for the expeditious 77 78 Id. at 1. Id. at 5. 51 implementation of the measures necessary for achieving its final goal by 2030. In so doing, the state would be able not only to determine which actions and measures to pursue to reduce emission rates, but also to choose a reasonable schedule for implementing those measures consistent with reliability needs, infrastructure development, and least-cost planning to provide affordable power to customers. There would be no requirement that states achieve any particular target prior to 2030. Such an approach is generally consistent with the statutory language of section 111(d), which gives the states the primary responsibility for developing a plan for the establishment and implementation of the performance standards applicable to affected existing sources. Furthermore, the statute does not impose any specific time frame for the implementation of performance levels set by the federal guidelines. This silence clearly gives the EPA the discretion to allow states to achieve their state-specific emission goals based on various factors enumerated in section 111, including costs, energy requirements and the remaining useful life of existing source. V. Building Block 1 A. The 6 Percent Heat Rate Improvement Target For Coal-Fired EGUs Assumed For Building Block 1 is Unachievable. In its evaluation of CO2 abatement measures, the EPA has identified the reduction in carbon intensity of generation at individual affected coal-fired EGUs through HRI as the basis for the Building Block 1 component of the BSER the Agency used in its development of the state CO2 emission rate targets. In this context, HRIs are synonymous with an improvement in coalfired EGU efficiency as more efficient coal-fired EGUs tend to have lower heat rates and therefore produce less CO2 on a pound per MWh basis. 52 For Building Block 1, the EPA proposes that a 6 percent average HRI target is achievable across each state's coal fired EGU fleet and will lead to a 6 percent reduction in CO2 emissions from the affected units. In developing the 6 percent HRI target, the EPA heavily relied on the gross HRI methods described in the 2009 Sargent & Lundy (S&L) report79 "Coal-Fired Power Plant Heat Rate Reductions," alongside a statistical analysis of reported gross generation and heat rate data from the years 2002-2012. The EPA, however, has made incorrect assumptions and factual errors in its development of the 6 percent HRI goal for Building Block 1. First, the EPA calculated the proposed average 6 percent HRI potential using two fundamentally different and equally flawed methods. The two additive approaches the EPA used to determine the 6 percent HRI target are:  A 4 percent HRI based on the implementation of low to no-cost "best practices" that were mentioned in the S&L report. Instead of using actual reports of HRI experience or even the estimated benefit ranges from the S&L report, the 4 percent HRI was merely calculated from a statistical analysis of gross heat rate data from 2002-2012 and the erroneous assumption that reducing heat rate variability in the data will produce an average heat rate improvement.  A 2 percent HRI resulting from high cost equipment upgrades listed in the S&L report that the EPA has assumed have both additive benefits and are still available to most units to implement. Nowhere in the S&L report does it even suggest that heat rate 79 See Davis Hasler, Coal-fired Power Plant Heat Rate Reductions Sargent & Lundy (Jan. 22, 2009) (Although EPA funded and reviewed the report, the report has not been approved by the EPA for publication as an EPA report. All estimated capital and installation costs contained in the report were obtained from work in progress and vendor quotes as of the year 2008 and the costs represent values of new equipment purchased in the year 2008. The authors note that the costs contained in the report “are not indicative of those that may be expected for a specific facility due to variables such as equipment, material, and labor market conditions and site specifications.”), http://www.epa.gov/airmarkt/resource/docs/coalfired.pdf. 53 improvements from the various methods discussed in the report are or can be considered to be additive. The EPA has also assumed that the majority of these measures have not yet been employed by coal-fired EGUs, that no limitations or barriers exist that would prevent their adoption, that the actual HRI will not vary by unit, and the HRI gains will not degrade over time. The flawed methods used by the EPA have resulted in the Agency assigning an unachievable 6 percent HRI assumption for Building Block 1. In addition to the flawed methodology, the EPA has only provided assumptions as to what HRIs may already have been implemented by coal-fired EGUs rather than conducting and presenting the results of a thorough analysis that looks at each individual unit. There are also several other serious oversights in the EPA evaluation which would greatly affect the calculation of any HRI target.  The EPA’s use of gross heat rate data to assess HRI potential is inconsistent with the use of net heat rate data in its calculation of the state goals.  The EPA’s broad application of a nationwide average 6 percent HRI goal in calculating individual state CO2 emission rate targets has failed to account for unique differences in coal-fired EGUs that affect potential HRI opportunities at individual unit, state, regional, and national levels.  The EPA neither analyzed nor addressed the adverse heat rate impacts due to the additional cycling, increased load variability, and reduced load factors that would result from the displacement of coal-fired generation from Building Blocks 2, 3, & 4.  The EPA neither analyzed nor addressed the effects of other regulations under the CAA that will actually serve to increase average net heat rates over time by adding auxiliary loads from additional pollution controls. 54  The EPA failed to take into consideration potential New Source Review impediments to the implementation of HRIs in its evaluation of Building Block 1.  The EPA’s overestimate of the HRI potential has in turn led to inaccurate fuel savings estimates for affected EGUs. The issues identified above related to the EPA’s flawed Building Block 1 evaluation have led the EPA to severely overstate the ability for the coal-fired EGU fleet to improve average heat rates. This has in turn led to state CO2 emission rate reduction goals that are unreasonable. 1. The EPA’s Use of a Single Report Undermines its Building Block 1 Six Percent Heat Rate Improvement Goal. The EPA relied almost exclusively on the 2009 S&L report "Coal-Fired Power Plant Heat Rate Reductions" in its determination of the “best practices” and “equipment upgrades” that could be employed to improve heat rates.80 While “best practices” and “equipment upgrades” can improve heat rates and reduce emission rates, the use of a single report is not a sufficient basis for concluding that the nationwide coal-fired EGU fleet can, on average, achieve a 6 percent HRI. It should be noted that the EPA examined reported gross heat rate data in the context of the “best practices” analysis, but ultimately rejected without explanation this approach for the purpose of assessing the HRI potential of "equipment upgrades." The S&L report is a good guide as to what potential heat rate improvement methods may be available, but it is not authoritative or exhaustive. In its interpretation of the S&L report, however, the EPA has failed to recognize that the report was specific to full-load operation, that the HRI methods mentioned were not necessarily cumulative, and that unit specifics may limit or 80 GHG Abatement Measures TSD at 2-33. 55 prevent the use of the suggested HRI opportunities. The S&L report also did not address the impact of flexible operations such as cycling, load following, and extended low load periods on coal-fired EGU heat rates or the potential change in benefit of the identified HRI methods due to flexible operation. The S&L report was published in 2009 based on data and costs available in 2008. Many of the key heat rate improvement opportunities addressed in the report have already been implemented at coal-fired EGUs alongside the installation of pollution controls such as selective catalytic reduction and flue gas desulfurization technologies and fall within the 2012 baseline used in the development of the state goals, and are no longer available to contribute to the 6 percent goal. Any estimates of implementing HRI on existing coal-fired EGUs must therefore be based on an analysis of the remaining HRI potential at individual units. Finally, the realistic HRI achievable for any given coal-fired EGU is unique to its original design limitations, age, condition, additions of pollution controls, and the degree it employs flexible operations. Therefore, unit specific research and data must be used to assess HRI because there is no such thing as an average coal-fired EGU, and the EPA’s approach that resulted in the identification of a national average HRI is without merit. 2. The EPA’s Assumption That “Best Practices” Can Improve the Heat Rate of the Coal-Fired EGU Fleet By Four Percent On Average Is Not Supported By Data. The EPA’s assumption that fleet-wide, existing coal-fired EGUs can improve heat rates by 4 percent through Operations and Management (“O&M”) “best practices” is not supported by the EPA’s underlying assessment of gross heat rate data and, therefore, is not reasonable. The EPA’s “best practices” analysis begins with the premise that any variability in a unit’s heat rate 56 represents an opportunity to improve heat rate and reduce CO2 emissions.81 The EPA further assumes that most heat rate variability can be attributed to deficient O&M practices and can be eliminated through employment of improved O&M "best practices.” While the EPA is correct that improved heat rates can result in reduced CO2 emissions from coal-based EGUs,82 the EPA is not correct that heat rate variability can be eliminated, nor has the EPA demonstrated a detailed understanding as to the causes for the claimed variability in heat rate. As discussed in more detail below, many factors contribute to heat rate variability; some of these are outside the control of the unit operator and can never be eliminated. More importantly, the EPA’s assumption that improved O&M practices can reduce heat rate variability ignores the existence of the many factors and is unsupported by the Agency’s analysis, undermining the EPA’s determination that a 4 percent HRI from "best practices" is both reasonable and economic.83 For the “best practices” analysis, the EPA examined affected EGU hourly heat rate data for 884 coal-fired EGUs for the years 2002-2012 to determine the amount of variability in heat rates across the existing fleet.84 Recognizing that ambient temperature and hourly load levels (capacity factors) have a direct impact on a unit’s heat rate and are outside a unit’s control, the EPA grouped the hourly data into “bins” in an attempt to control for these variables.85 The Agency assumed that any remaining variability in heat rate data in the various bins would be “an indication of the degree of technical potential to improve the consistency with which optimal heat rate performance is achieved by adopting operating and maintenance best practices.”86 81 79 Fed. Reg. at 34,860. Id. at 34,905. 83 Id. at 34,860. 84 Id. at 34,860. 85 GHG Abatement Measures Technical Support Document at 2-15. 86 79 Fed. Reg. at 34,860. 82 57 For each bin, the EPA then calculated a “top decile” heat rate performance from the 10th percentile lowest value in each bin.87 The EPA further calculated a range of 1.3 to 6.7 percent “technical potential for improvement of the average heat rate of the entire fleet of coal-fired EGUs” by “assuming that between 10% and 50% of the deviation from top decile performance in each subset of hourly heat rate observations within defined ranges of temperature and load could be eliminated through adoption of best practices.”88 Based on this analysis, the EPA concluded that: A reasonable estimate for purposes of developing state-specific goals is that affected coal-based steam EGUs on average could achieve a 4% improvement in heat rate through adoption of best practices to reduce hourly heat rate variability. This estimate corresponds to the elimination, on average across the fleet of affected EGUs, of 30% of the deviation from top-decile performance in the hourly heat rate for each EGU not attributable to hourly temperature and load variation.89 3. The EPA’s Bin Analysis Does Not Demonstrate That Most Heat Rate Variability Can Be Attributed to Deficient O&M Practices. The EPA’s bin analysis described above is flawed and does not demonstrate that most heat rate variability is caused by deficient O&M practices. The EPA’s assumption that reduced variability in heat rate implies an improvement in a unit’s heat rates indicates a failure to understand what “variability” is and what actually causes it. Variability is change relative to an average value, not relative to a theoretical optimal value (or top decile). Nevertheless, the EPA conducted a regression analysis of 884 generating units and concluded that units with more variable heat rates tend to have higher heat rates.90 Even if this were true, the regression analysis only identified the relationship between variability and heat rates; it did not identify the cause of the variability. The EPA has made the assumption that the 87 Id. at 34,860. Id. at 34,860. 89 Id. at 34,860. 90 Abatement Measures TSD at 2-22. 88 58 cause must be deficient O&M, but that assumption is wrong. There are other factors that cause this variability, such as EGUs engaging in flexible operations such as cycling, load following, and extended low load periods. The 2002-2012 data period the EPA analyzed also included a severe economic downturn, a drop in natural gas prices which affected dispatch of coal firedEGUs, and changes in continuous emissions monitor (“CEMs”) reporting methodology. The EPA has made no effort to determine whether any of these factors could have led to the observed variability or change in heat rate trends. The EPA cited nine different categories of factors influencing heat rate.91 The EPA’s analysis attempted to partially account for some of these factors, including load factor and ambient temperature. Other factors that affect heat rate include unit size and steam conditions. The EPA’s only attempt to recognize and control for the range of factors that might affect variability in heat rate was an assumption that 50 percent of the variability observed in bin data was caused by deficient O&M practices. In an attempt to be "conservative," the EPA then adjusted that assumption down to 30 percent in the estimate of heat rate improvement potential for "best practices." The EPA's arbitrary assumption was not supported by their analysis and did not identify the actual cause(s) of the observed variability in heat rates. If heat rate variability cannot be directly attributed to deficient O&M practices, then the EPA has no basis to assert that O&M “best practices” will result in a HRI of 4 percent or any percent. What the EPA’s own analysis likely indicates is that load factors, not O&M practices, play a significant role in explaining coal-fired EGU heat rate variability.92 The EPA’s bin analysis reduced the effect of load factor change, but each bin itself includes a 10% range of load 91 92 GHG Abatement Measures TSD at 2-4 to 2-5. Id. at 2-25. 59 factors.93 An International Energy Agency (“IEA”) report found that a 10% change in load factor can result in a 4 percent change in heat rate.94 Thus, the bin approach reduced, but did not eliminate, the very significant impact of variable load factor on heat rate. It is well proven that load factor (or capacity factor) has an inverse relationship with heat rate for coal-fired EGUs. The higher the load factor, the lower the heat rate. Conversely, lower capacity factors (and increased cycling) increase average heat rates and also increase heat rate variability. In the integrated electric grid, economic conditions are causing coal-fired EGUs increasingly to be dispatched to respond to load rather than running as base load units. Therefore unit owners and operators cannot control load factor on these EGUs to address concerns about heat rate. If the variation within bins is significantly influenced by load factor, heat rate variability would not be able to be addressed by the implementation of O&M "best practices" at all.95 4. The EPA Inappropriately Considered Duke Energy’s Gibson Unit 1 as a Unit That Has Demonstrated a 3 to 8 Percent Heat Rate Reduction. In a technical support document developed in support of its proposed 6 percent heat rate improvement target for building Block 1, the EPA identified from the national generating inventory 16 units the Agency claims demonstrate the feasibility of achieving gross heat rate reductions of at least 3%, on a year-on-year basis, as determined over an 11-year period.96 One of the 16 generating units the EPA relied upon for its analysis is Duke Energy’s Gibson Station 93 Id. at 2-24 to 2-25. See Power Generation from Coal, Measuring and Reporting Efficiency Performance and CO 2 Emissions, IEA/CIAB, at 20 (2010)(A 2010 report by the International Energy Agency found that a 10% reduction in capacity factor (from 50% to 40%) can increase heat rate by 4%), http://www.iea.org/ciab/papers/power_generation_from_coal.pdf. 95 In fact, Building Blocks 2, 3, and 4 will each exacerbate load factor variability. 96 Technical Support Document (TSD) for Carbon Pollution Guidelines for Existing Power Plants: Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary Electric Utility Generating Units, Docket ID No. EPA-HQ-OAR-2013-0602, page 2-32. 94 60 Unit 1 in Owensboro, Indiana. The apparent reduction in the heat rate of this unit was influenced by a number of factors that have nothing to do with an actual reduction in the unit’s heat rate. Therefore the gross heat rate history of this unit does not support the EPA’s conclusion that targeted heat rate reductions of up to 6 percent are feasible. The EPA erred in its reliance on the Gibson Unit 1 data because the CEMs data for this unit are not independently representative of the analysis the EPA conducted. First, prior to the spring of 2007, the Gibson Unit 1 flue gas exited a single common stack that was shared with Gibson Unit 2. Per the CEM protocols of Part 75, heat input measurements from the single common stack were allocated to the individual units on a pro-rata basis using gross unit load. As a result, the CEM data do not independently represent the performance of Gibson Unit 1. In the Fall of 2007, Gibson Unit 1 was retrofitted with a new wet flue gas desulfurization system (“FGD”), including a new stack and a completely new CEM system. Because of these changes, the CEM data before and after this event are not comparable as the EPA protocol allows up to a 7.5% Relative Accuracy Test Audit limit for the flow monitor, and 0.7% for the CO2 monitor (the measurements from the flow monitor and the CO2 monitor are used in the CEM heat input calculation). Therefore, changes in the Gibson Unit 1 heat rate based on the CEM data cannot be differentiated between the change in the CEM itself and any actual gross heat rate improvement. This is only further emphasized by the fact that the improvement being sought is within the established measurement accuracy of the instruments, and should therefore be completely discounted. Lastly, when the selective catalytic reduction (“SCR”) (2005) and flue gas desulfurization (“FGD”) (2007) were added to Gibson Unit 1, the auxiliary power consumption for the unit increased, also increasing the net heat rate, even while the gross heat rate remained constant. Since the EPA’s analysis is only (and inappropriately) relying on gross generation and 61 heat input data, it does not capture the change in the true total net heat rate, which is the basis for compliance with the Clean Power Plan. 5. The EPA Did Not Account For Increases in Heat Rate From the Installation of Pollution Control Equipment in Its Development of the HRI Targets. The EPA has failed to account for and provide an allowance for the impact of present and future pollution control equipment on coal-fired EGU heat rates in Building Block 1. Electric generating unit owners have often performed the kind of HRIs discussed in the S&L report in conjunction with pollution control projects in order to minimize the resulting increases in heat rate, but the heat rate improvements are generally outweighed by the new parasitic auxiliary loads created by the pollution control retrofits. Both a coal-fired EGU’s heat rate and heat rate variability are negatively affected by the operating load and auxiliary power requirements needed to run pollution controls and associated equipment. In particular, the EPA has overlooked the negative impact on coal-fired EGU efficiency as units will see significant increases in cycling due to the implementation of Building Blocks 2, 3, and 4. These negative heat rate impacts are not reflected in the 2012 generation data that are the baseline for the EPA’s proposed state goals. The impacts of implementing Building Blocks 2, 3, and 4 as EPA has proposed will very likely reduce or completely eliminate the potential for any overall heat rate improvement for coal-fired EGUs. Many coal-fired EGUs are installing pollution control systems to comply with other regulatory requirements, such as the Mercury and Air Toxics Standards (“MATS”), while others must install further retrofits in coming years to comply with regional haze requirements, 316(b) requirements, and steam electric effluent guidelines requirements. Those systems will reduce net 62 generation and increase net heat rate and CO2 emission rates as acknowledged by the EPA.97 As the EPA has already noted, controls for sulfur dioxide and acid gases will increase heat rates and CO2 emissions.9899 The EPA’s own analysis indicates that 20 GWs of coal-based units will install dry scrubbers and 63 GWs will upgrade currently installed scrubbers in 2015-2016 to comply with the MATS.100 Also, various water regulations may force many coal-fired EGUs to move from once through to evaporative or air cooling, further increasing auxiliary loads and heat rates. The EPA's own October 2010 report "Available And Emerging Technologies For Reducing Greenhouse Gas Emissions From Coal-Fired Electric Generating Units" states: The SO2 emissions from new coal-fired EGUs, or retrofitting of an existing facility without specific SO2 controls, are controlled using flue gas desulfurization (FGD) technology to remove the SO2 before it is vented to the atmosphere. The selection of the type of FGD technology will impact overall GHG emissions. All FGD processes require varying amounts of electric power to operate, which contributes to the overall parasitic load of the unit. The FGD parasitic load requirements are typically between 1-2% of the gross output of the facility. Because the EPA failed to consider the effect of present and future pollution control requirements on EGU heat rate, it has set an unsupported and unattainable HRI requirement in Building Block 1. As such, it does not reflect BSER, and even if EPA’s Proposed guidelines consisted solely of Building Block 1, its proposal would be arbitrary and indefensible. As proposed, the EPA would force affected EGUs to overcome the energy penalties associated with these controls and then achieve an additional 6 percent heat rate improvement on top of that 97 GHG Abatement Measures TSD at 2-4. 79 Fed. Reg. at 34,859, n.113. 99 EPA recognizes that the controls themselves increase CO2 emissions because of the use of certain reagents. EPA asserts that these increased CO2 emissions will be offset by decreased fuel usage due to increased unit efficiency. EPA completely ignores the parasitic load associated with these controls and the detrimental effect this will have on unit heat rates. 100 See Regulatory Impact Analysis for the Final MATS, Docket No. EPA-HQ-OAR-2009-0234, at 3-15. 98 63 through HRIs that may no longer be available. In developing the Building Block 1 target, the EPA appears to completely ignore the obligations imposed on EGUs by the CAA and other environmental statutes. 6. The EPA Should Not Have Considered Units That Are Expected to Close When Assessing Fleet-Wide Heat Rate Improvement Potential Through Statistical Analysis. There is no evidence that the EPA considered the impact of retiring coal units on the results of its HRI analyses. If a unit closes, there can be no HRI potential at that unit. The EPA ran a sensitivity analysis that excluded units that have announced retirement dates before 2016.101 However, this did not include the additional 46-49 GW of coal-based units the EPA projects will retire as a result of compliance with the Proposed Guidelines.102 Presumably, these units have higher design heat rates and have more variability in heat rate because they are older and tend to operate at relatively low capacity factors. Accordingly, they might appear (statistically) to have significant heat rate improvement potential, but this potential will not be realized if these units retire. Therefore, the EPA should exclude these 46-49 GWs when assessing the future HRI potential of the existing coal-based fleet. Inclusion of these units likely inflated the EPA’s assessments of available HRI through O&M “best practices.” 7. The EPA Has Not Provided a Reasonable Basis For the Conclusion That “Equipment Upgrades” Can Improve Heat Rates By Two Percent. The EPA has concluded that unit-specific “equipment upgrades” could result in a HRI of 2 percent at coal-fired EGUs.103 The EPA’s conclusion is unsupported by its analysis. Accordingly, the EPA lacks a sufficient and reasonable basis for concluding that equipment upgrades can achieve an average HRI of 2 percent across the existing coal-fired EGU fleet. 101 GHG Abatement Measures TSD at 2-35. Resource Adequacy and Reliability Analysis (Resource Adequacy TSD) at 1. 103 GHG Abatement Measures TSD at 2-34. 102 64 The EPA arrived at its 2 percent HRI target from "equipment upgrades" by separating the 13 different HRI measures listed the S&L report into two categories based on their average estimated $/kW costs.104 The four higher cost measures were then characterized as “equipment upgrades.” These four measures are:  Economizer replacement;  Acid dew point control;  Combined VFD (variable frequency drive) and fan replacement; and  Turbine overhaul (which appears to include rotor replacement). The EPA simply added the average estimated Btu/kWh improvements of the four "equipment upgrades."105 Based on this overly simplistic and technically unsupportable approach, the EPA concluded that these four specified equipment upgrades could provide a 4 percent heat rate improvement if all were applied on an EGU that has not already made them. The EPA then “conservatively” reduced the target to 2 percent as “some units may have applied at least some of the upgrades.”106 As discussed above, this methodology erroneously assumes that the heat rate improvements from these upgrades are cumulative and that they provide consistent long-term benefits. In reality, the combined heat rate benefit from applying all four of these upgrades will be less than the sum of each measure’s individual heat rate benefit when applied to an EGU. These heat rate benefits will begin to degrade immediately once the unit returns to service. Also, the EPA’s reliance on the average Btu/kWh improvement of each measure is flawed because the 104 Id. at 2-33. Id. 106 Id. at 2-33, 2-35; 79 Fed. Reg. at 34,860. 105 65 potential benefit of each upgrade is highly unit-specific. The four HRI measures may not even be feasible for many EGUs due to design limitations or backend pollution controls.107 For example, the S&L report states that additional surface area can be added to an economizer to gain a heat rate improvement by recovering heat and thereby reducing exit gas temperature. However, over 50 percent of coal-fired EGUs presently have SCR installed for NOx control and that percentage will only grow as smaller units are retired and larger units continue to be retrofitted to meet present and future environmental regulations under the CAA. Reducing the temperature out of the economizer can interfere with SCR operation as SCRs require minimum operation temperatures to function properly across the load range. The need to maintain a minimum SCR operating temperature could eliminate a large percentage of the eligible EGUs that may otherwise be capable of increasing their economizer surface area. A similar limitation is imposed on employing acid dew point control due to potential downstream effects on electrostatic precipitators (“ESP”) and FGDs. 8. The EPA Has Not Determined Which "Equipment Upgrades” Already May Have Been Implemented. The EPA’s attempt to account for coal-fired EGU specifics and whether HRI "equipment upgrades" have already been performed by "conservatively estimating" a potential HRI improvement of 2 percent instead of 4 percent supports the argument that the EPA’s approach is arbitrary and unreasonable. The EPA’s determination that only half of the possible equipment upgrades may have already been deployed is unsupported by any data, and the EPA has failed to explain how it ensured that any of the HRI improvements that were attributed to O&M “best practices” in its statistical bin analysis should not more properly be attributed to these 107 See National Coal Coalition Report at 70 (“The benefits and cost are highly variable and depend on the specifics of any one site.”). 66 "equipment upgrades” or vice versa. It should be noted that turbine overhauls are already routinely done on most EGUs to prevent maintenance issues and gain back some of the efficiency lost over time due to equipment degradation. Therefore, significant HRI from steam turbine upgrades (the most expensive measure) are probably more appropriately deemed as a best practice, since they are routine. Once either an overhaul and/or upgrade is performed, the benefits will once again immediately begin to degrade until the next overhaul. The remaining HRI potential through "equipment upgrades" is likely even much lower, given that many of these measures have been already applied on EGUs.108 The EPA cannot require affected EGUs to duplicate emission reductions they have achieved using measures they have already taken. The EPA can identify equipment upgrades as potential BSER, but it should leave it to the individual state to assess what equipment upgrades have already been implemented by specific affected coal-fired EGUs in order to determine what, if any, additional HRI is actually achievable. This is consistent with the language of section 111(d) which directs the states to consider such things as remaining useful life and other unit-specific factors. 9. The EPA Did Not Address the Adverse Heat Rate Impacts Due to Changes in Operation and Displacement of Generation Resulting From Building Blocks 2, 3, & 4. The EPA did not address the adverse impacts on coal-fired EGU heat rates when engaged in the flexible operations (cycling, load following, and extended low load periods) that would result from the implementation of EPA’s proposed Building Blocks 2, 3, and 4. The vast majority of large coal-fired EGUs were originally designed for an optimal heat rate when baseloaded using a specific fuel. Their efficient operation requires maintaining mass and energy balances between hot gases and water/steam flows and among different components at all times 108 Id. at 70. 67 and across all loads while adapting to changing demand, all while firing what is becoming an increasingly variable fuel supply. Flexible operation reduces efficiency, increases heat rate variability, and reduces reliability through accelerated equipment wear and stress. Additionally, an EGU's fixed losses and parasitic auxiliary power draws increase as a percentage of load as load decreases. While the EPA acknowledges that coal-fired EGUs have higher heat rates (i.e. are less efficient) when operating as load following units and during periods of startup and shutdown,109 there is no indication that this fact was considered by the EPA as part of its Building Block 1 BSER determination. In development of Building Block 1, the EPA has failed to recognize that coal-fired EGU heat rates will only degrade rather than improve as load variability increases and capacity factors are reduced due to the system interactive effects from the displacement of coal-fired generation by redispatch of NGCC units, increased use of renewable power (likely an erratic supply), and growth in end-use energy efficiencies as proposed under the EPA’s Building Blocks 2, 3, and 4. The planned and forced retirements of the older and smaller coal-fired EGUs caused by the economic realities of numerous environmental regulations affecting coal-fired EGUs, including the EPA’s Proposed Guidelines, will only result in the remaining large coal-fired EGUs shouldering an increasing burden of maintaining a variable load. These competing demands will eliminate any efficiency gains made through implementing HRIs and lead to worsening heat rate trends in general. Additionally, the EPA did not take into account that the reduced capacity factors and increased load variability resulting from implementing Building Blocks 2, 3, and 4 will also degrade the value of HRI. As the heat rate benefits in the S&L report were specific to full load, 109 GHG Abatement Measures TSD at 2-5, 2-21. 68 increased flexible operations will move the actual benefits towards or even below the low end of the estimated ranges. The effects of cycling on coal-fired EGUs will also lead to accelerated equipment wear and maintenance needs, further degrading average EGU efficiency across all loads and increasing operating costs. Subsequently, in failing to recognize and address the competing requirements of Building Blocks 2, 3, and 4 against the goal of improving coal-fired EGU heat rates in Building Block 1, the EPA has overestimated the HRI benefits and fuel cost savings from its implementation. This has resulted in the calculation of state goals that are unreasonable and unjustified. In reality, the Proposed Guidelines will cause average coal-fired EGU efficiency and thus their CO2 lb./MWh emissions to increase regardless of the number of HRIs implemented, which will only serve to increase overall operating costs. 10. The EPA Has Overestimated the Cost Savings Associated With Heat Rate Improvements. When determining the BSER, the EPA is required to consider, among other things, cost.110 The EPA asserts that the costs of the projected HRI are reasonable based on cost data from the 2009 S&L report and because fuel savings will offset the costs of HRI measures.111 Neither of the EPA’s assertions about HRI costs are reasonable. First, the EPA’s cost assessment is based on information from the S&L report.112 The cost estimates in the S&L report were based on 2008 data, which is no longer current. The EPA's assessment should use more recent data and include additional sources in order to better substantiate costs. 110 CAA section 111. GHG Abatement Measures TSD at 2-33 to 2-34. 112 79 Fed. Reg. at 34,861. 111 69 Second, the EPA’s core argument in support of the reasonable cost of the HRI that is part of the EPA’s BSER determination and which forms part of the basis of the state emission rate goals is that “any heat rate improvement made for the purpose of reducing CO2 emissions will also reduce the amount of fuel the EGU consumes to produce its electricity output.”113 Using cost estimates from the S&L report, the EPA calculated an annualized cost per kilowatt hour (“kwh”) of HRI measures.114 The EPA then calculated an annualized fuel cost to estimate the average fuel savings related to a 6 percent HRI.115 However, Building Blocks 2, 3, and 4 are specifically designed to reduce fuel use by coal-fired EGUs but this was not factored into the EPA’s Building Block 1 cost assessments. If it had been, it would have resulted in reduced fuel savings from HRIs. Heat rate improvements will reduce fuel costs, on a per kilowatt (“kW”) basis, but the EPA’s analysis, which focuses on annualized costs, ignores the lag between capital expenditures and fuel cost savings. Immediate HRI measure capital costs may be financed, which spreads the costs over time. This financing is dependent on continued operation of the unit to create a revenue stream that allows the capital costs to be repaid over time. The EPA’s own analysis indicates that many existing coal-based units will be retired by 2020 and that the utilization of the remaining units will decrease as part of states’ compliance efforts in meeting their interim and final goals.116 This dramatically shortens the payback period and reduces the electricity sales available to support capital cost investments in HRI measures. 113 Id. at 34,861. Id. 115 Id. 116 RIA at 3-32. 114 70 To some extent, the EPA recognizes this, noting that “reductions in the utilization rates of coal-fired EGUs anticipated from other components proposed for inclusion in … [BSER] would tend to reduce the fuel savings associated with [HRI], thereby raising the cost effectiveness of achieving the CO2 reductions.”117 But the EPA quickly dismisses—without any analysis —the impact that reduced utilization would have on the reasonableness of HRI costs, stating “[n]evertheless, we still expect that the majority of the investment required…would be offset by fuel savings.”118 Accordingly, the EPA has not adequately supported its claims that reductions associated with HRI measures can be achieved at reasonable cost. 11. The EPA Should Defer to the States to Determine the Appropriate Levels of Heat Rate Improvement. For the reasons identified above, the EPA should acknowledge that it is simply not feasible for the agency to perform an appropriate assessment of potential HRI opportunities across the fleet of existing coal-fired EGUs due to the unit-specific nature of potential HRI opportunities, and the need to perform evaluations on a case-by-case basis. Therefore, if the EPA continues with a determination that HRI is BSER for existing coal-fired EGUs, it should defer to the states to determine the level of HRI that is appropriate for the existing coal-fired EGUs in their states. Only the states, working with the affected sources, can perform the unitspecific assessment that is required, factoring in other regulatory requirements that would apply to the affected sources and their impact on unit heat rates. The statute requires that EPA permit the states to take these factors into consideration. 117 118 79 Fed. Reg. at 34,861. Id. at 34,861. 71 In its October 30, 2014 NODA the EPA requests comment on the idea of a phasing-in of the Building Block 1 heat rate improvement.119 The problem with that idea is that as detailed above, no amount of time will allow for an average 6 percent improvement in the heat rate of coal-fired EGUs because that level of heat rate improvement is simply not achievable. B. New Source Review Issues. Building Block 1 of the EPA’s proposed BSER consists of measures aimed to reduce CO2 emissions from coal-fired EGUs by improving heat rate, which reduces the amount of fuel needed to produce the same amount of electricity. Heat rate improvements increase efficiency and “yield important benefits to affected sources by reducing their fuel costs.”120 In the Proposed Guidelines, the EPA noted that “several studies have examined the opportunities to employ heat rate improvements” at coal-fired EGUs, and specifically cited a 2009 report by S&L as identifying “equipment upgrades at a facility that could provide total heat rate improvements in a range of approximately 4 to 12 percent.”121 Likewise, the EPA cites its 2014 Technical Support Document for GHG Abatement Measures, which also lists upgrades that may be employed to reduce heat rate.122 The projects identified in the S&L report and the GHG Abatement Measures TSD include upgrades to the following components: soot blowers, boiler feed pumps, economizers, turbines, boilers, air heaters, feedwater heaters, condensers, FD and ID fans, pulverizers, condensate pumps, flue gas conditioning systems, selective catalytic reduction systems, ash handling systems, neural network optimization systems, electrostatic precipitators, and system 119 Id. at 64,548. Id. at 34,928. 121 Id. at 34,859. 122 Id. 120 72 controls.123 The EPA further explained that “EGUs achieve heat rate improvements by . . . installing and using equipment upgrades . . . such as extensive overhaul or upgrade of major equipment (turbine or boiler) or replacing existing components with improved versions.”124 Every one of these upgrades has been targeted by the EPA and citizen plaintiffs as triggering the NSR provisions of the CAA. An analysis of the EPA notices of violation, citizen notices of intent to sue, and complaints available in the public record since the EPA began its NSR enforcement initiative in 1999 conducted by the Utility Air Regulatory Group identified over 400 efficiency improvement projects targeted by the EPA or citizens since 1999 as allegedly violating NSR.125 These projects are the same types of projects identified in the S&L report and GHG Abatement Measures TSD. Moreover, during that same period, the EPA and citizens have targeted almost 600 other projects as violating NSR.126 These projects—like the projects cited by S&L and the EPA—are important to maintaining and improving the efficiency of coal-fired generating units. The projects consist of “like-kind replacement of worn equipment,” which the EPA also identifies as essential to maintaining and improving the efficiency of coal-fired generating units.127 It’s clear that the EPA recognizes the potential NSR consequences of implementing Building Block 1, but states that it expects there will be “few instances” where “an NSR permit 123 See Sargent & Lundy LLC, COAL-FIRED POWER PLANT HEAT RATE REDUCTIONS at 2-1 to 5-4 (Jan. 22, 2009) (identifying projects); U.S. EPA, TECHNICAL SUPPORT DOCUMENT FOR CARBON POLLUTION GUIDELINES FOR EXISTING POWER PLANTS: EMISSION GUIDELINES FOR GREENHOUSE GAS EMISSIONS FROM EXISTING SOURCES, GHG ABATEMENT MEASURES, at 2-1-16 (June 10, 2014). (“GHG Abatement Measures TSD”). 124 GHG Abatement Measures TSD at 2-16. 125 See Attachment A to the Comments of the Utility Air Regulatory Group on the United States Environmental Protection Agency’s Carbon Pollution Emission Guidelines For Existing Stationary Sources: Electric Utility Generating Units; Proposed Rule, December 1, 2014. 126 Id. 127 See GHG Abatement Measures TSD at 2-16. 73 would be required.”128 Duke Energy agrees that very few efficiency projects, if any, should trigger NSR. Efficiency improvements of the types identified in the S&L report constitute routine repair and replacement of deteriorated components and do not trigger NSR. But clearly these views are not shared by the EPA’s enforcement arm, as is evident from the hundreds of projects targeted in the enforcement initiative since 1999. Based on the history of the EPA’s NSR enforcement initiative, the EPA’s statement that there will be “few instances” in which Building Block 1 projects would trigger NSR is hardly reassuring. Over 20 years ago, EPA made similar statements regarding life extension projects amid concerns that EPA’s determination that led to the Seventh Circuit’s decision in Wisconsin Electric Power Co. v. Reilly, (“WEPCo”),129 would apply to such projects. At that time, the EPA told industry that WEPCo would not “significantly affect power plant life extension projects.”130 Moreover, in the preamble to the 1992 NSR reform rule, known as the WEPCo rule, the EPA confirmed that whether repair and replacement projects are judged routine would be determined with respect to industry practice.131 As the EPA knows, however, utilities relying on these and similar statements regarding repair and replacement projects, including Duke Energy, were then targeted about a decade later for allegedly violating NSR for performing those very projects. Moreover, even if the EPA believes there will be “few instances” where an NSR permit would be required, there is no suggestion that all states or citizens share that belief. Citizen plaintiffs have been just as active as the EPA in litigating NSR suits over the past 15 years. Even when those citizen suits have lacked merit, they often delay the implementation of efficiency 128 79 Fed. Reg. at 34,859. 893 F.2d 901 (7th Cir. 1990). 130 W. Rosenberg letter to J. Dingell at 5-6 (June 19, 1991). 131 57 Fed. Reg. 32,314, 32,326 (July 21, 1992). 129 74 improvement projects, take several years to litigate, are very expensive, and drain scarce resources of the parties and courts.132 For this reason as well, the EPA’s assurances provide no comfort to utilities who are routinely targeted by citizens for alleged NSR violations relating to equipment upgrades. The threat of litigation is compounded by the fact the EPA maintains it can bring a suit alleging an NSR violation years after a project is undertaken and regardless of whether emissions in fact increase after the project. As a result, utilities implementing HRI projects that do not project an increase in emissions as a result of an equipment upgrade will face the ongoing threat of NSR litigation, years after their projects are completed. The EPA’s own recognition that “the NSR program has impeded or resulted in the cancellation of projects which would … improve … efficiency” confirms the need for regulatory certainty for utilities implementing Building Block 1.133 Otherwise, EPA’s Proposed Guidelines will create the same uncertainty and encounter the same problems that have beset the NSR program for the past 15 years. The EPA should eliminate the threat of protracted NSR litigation and provide a clear statement that any upgrades necessary to implement Building Block 1 do not trigger NSR. Instead, the EPA has suggested that the states themselves can provide the necessary relief from the efforts of the EPA’s enforcement arm and citizen groups for their sources as a part of 132 The same is often true for NSR enforcement actions. For example, in United States v. Cinergy, after more than a decade of litigation, a jury returned a verdict for EPA on only 4 of 14 projects, but even that limited success was reversed by the Seventh Circuit. 623 F.3d 455 (7th Cir. 2010). Likewise, EPA’s enforcement actions against Duke Energy and Alabama Power are still pending after nearly 14 years of litigation. United States v. Duke Energy Corp., No. 00-CV-1262 (M.D.N.C.); United States v. Ala. Power Co., No. 01-152 (N.D. Ala.). Trial has not been scheduled in either case. 133 The EPA, “New Source Review: Report to the President,” at 1 (June 13, 2002) (A-90-37, IV-A-5). 75 their state plans under section 111(d).134 The EPA’s first suggestion that states could somehow adjust statewide demand side measures and renewable energy requirements so as to counterbalance the supposed impact of unit-specific efficiency improvements on unit utilization is speculative at best. The EPA’s second suggestion of essentially imposing synthetic minor limits on all coal-fired sources (because, at least under the NSR enforcement initiative view of NSR, most, if not all, Building Block 1 projects likely trigger NSR) flies in the face of the supposed “flexibility” the EPA claims its Proposed Guidelines provide. Imposing such synthetic minor limits across the board would, for example, prevent a state plan from relying on the shutdown of smaller, less efficient units and increased utilization of larger, more efficient units. In summary, Building Block 1 of the EPA’s BSER in the Proposed Guidelines is based on measures that the EPA’s enforcement arm has declared illegal, as the EPA has at least implicitly acknowledged. Because the EPA’s justification of the state emission goals relies on the ability of sources to implement efficiency improvement measures, and because the EPA has failed to propose any credible regulatory provisions to otherwise address this issue, the EPA has failed to demonstrate the achievability of its goals as required by section 111. The EPA should eliminate the threat of protracted NSR litigation and provide a clear statement that any upgrades necessary to implement Building Block 1 do not trigger NSR. VI. Building Block 2 A. The EPA Has Not Shown That Building Block 2 Has Been Adequately Demonstrated Or Is Achievable. The EPA is proposing to find that it is achievable for affected EGUs in each state to shift generation from existing coal- and oil/gas-fired steam EGUs to existing NGCC units until those NGCC units reach a statewide maximum capacity factor of 70 percent (or 65 percent under the 134 79 Fed. Reg. at 34,928. 76 alternate goals EPA solicits comment on).135 The EPA based this conclusion on its observation that of 464 NGCC plants it identified with generation data in 2012, 10 percent had a capacity factor of 70 percent or greater.136 Using a different set of data, the EPA also observed that some units are capable of operating at greater than 70 percent capacity factor on a seasonal basis, with 16 percent and 19 percent of units operating at or above that level in the 2012 winter and summer seasons, respectively.137 Relying on this data, the EPA “assumed that 70% was a reasonable fleet-wide ceiling for each state” on an annual average basis.138 The EPA conclusion, however, is not supported by its own analysis, which fails to demonstrate that the 70 percent target for Building Block 2 redispatch is achievable by all affected NGCC units in the source category by 2020, the year the EPA assumes in its state goal calculations that all existing and under construction NGCC units begin operating at a 70 percent annual capacity factor. The EPA’s Building Block 2 analysis is insufficient because it fails to account for factors that can limit the ability of EGU owners to increase utilization of their NGCC units. For example, some units are unable to increase generation to any level approaching 70 percent due to technical limitations, permit limits, or gas and transmission infrastructure constraints. Other NGCC units will not be able to generate sufficient amounts above 70 percent to make up for these lower-utilization units. The fact that the EPA states that its Proposed Guidelines do not require that all affected NGCC units operate at a 70 percent capacity factor is irrelevant. Because the across-the-board 70 percent capacity factor assumption is part of the 135 79 Fed. Reg. at 34,864-66. GHG Abatement Measures TSD at 3-7 to 3-9. 137 79 Fed. Reg. at 34,863. 138 GHG Abatement Measures TSD at 3-9. 136 77 EPA’s proposed BSER determination, the Agency must show that it has in fact been adequately demonstrated. The EPA analysis fails to do this. The EPA’s assumption that each state’s entire fleet of existing NGCC units can match the operational level of the top 10 percent of units across the country is arbitrary and unsupported by fact. The EPA did not undertake any assessment of the differences between high- and lowcapacity factor NGCC units that may have led a small subset of those units to operate above a 70 percent capacity factor in 2012. The Agency acknowledged that units operating above 70 percent on an annual basis were “largely dispatched to provide base load power,” and that units operating above 70 percent on a seasonal basis typically “were idled or operated at lower capacity factors” during periods of lower demand.139 But the EPA did not examine whether the NGCC units providing base load power have different characteristics from the other existing NGCC units that were assumed to be capable of operating at a 70 percent capacity factor in the EPA’s Building Block 2 application, or whether units that were idled during periods of relatively low demand did so because of economic, technical, or regulatory constraints on their operations. Instead, the EPA assumed that all NGCC units are identical. The EPA, however, has failed to establish that the 10 percent of existing NGCC units operating at 70 percent capacity factor or higher in 2012 are representative of the remainder of NGCC units in the source category. In reality, many existing NGCC units face constraints that will prevent them from increasing their utilization to a 70 percent capacity factor. Some units may be located in areas that are designated as in non-attainment for a NAAQS, and as a result could have operating permits imposing mass limits on carbon monoxide (“CO”) or NOx emissions that would effectively establish a cap on those units’ operations. Other units were designed and maintained 139 Id. 78 for the specific purpose of operating in cycling duty rather than as base load. Many of these units would not be able to achieve the target utilization rate without significant upgrades and testing to ensure that they are technically capable of operating near full load on a continuous annual basis. In addition, their permitted emission limits may not allow them to operate at a 70 percent capacity factor. Further, for many existing NGCC units there is simply insufficient pipeline natural gas availability, or transmission infrastructure to permit operating year-round at a 70 percent capacity factor. The EPA does not acknowledge or adequately address the constraints preventing existing EGUs from operating at a 70 percent or higher capacity factor. The EPA completely ignores potential permit limits on NGCC unit operation and dismisses infrastructure concerns. The Agency’s primary response—that the allowance for “emission rate averaging across multiple units” within a state in the proposed emission guidelines—does not demonstrate that a 70 percent overall capacity factor is achievable.140 The EPA has made no attempt to determine whether each state will have a sufficient number of existing NGCC units that are able to generate sufficient electricity above a 70 percent capacity factor to make up for units that are not able to approach this level. The EPA also points to historic trends in an attempt to justify its assumption that sufficient infrastructure already exists to support Building Block 2. For example, the Agency notes that NGCC generation increased by 22 percent between 2011 and 2012, supposedly demonstrating that existing natural gas infrastructure can accommodate rapid increases in existing NGCC utilization.141 But what the EPA fails to note is that even after this expansion— 140 141 GHG Abatement Measures TSD at 3-15. GHG Abatement Measures TSD at 3-9 to 3-10. 79 which was largely a function of historically low natural gas prices in 2012, over half of the existing NGCC units that EPA examined still operated at a capacity factor below 50 percent, presumably due to the kinds of constraints the EPA ignores.142 In addition, the EPA relies on trends in hourly capacity factor to claim that a 70 percent capacity factor is an achievable goal. According to the Agency, the nationwide NGCC capacity factor during peak hours of the day averages 11 percentage points higher than the overall annual average, suggesting that the current system is able to support national average capacity factors “in the mid to high 50’s for NGCC for peak” (i.e., 11 percentage points higher than the 2012 national average capacity factor of 45.8 percent).143 The EPA does not explain, however, why it believes it is reasonable to expect that the current system can accommodate an additional 10-15 percentage points in order to reach a 70 percent average capacity factor over all hours of the day. The EPA’s effort to convert these load following or peaking facilities into base load EGUs also ignores the obvious question of which units will then become the load following and peaking units, both of which are required to effectively operate the electric generation system. Each resource has its strengths and weaknesses and is best suited to a specific role in the system of EGUs. The existing coal units cannot be converted into load following or peaking units. Many NGCC units might be able to increase capacity factors, while coal unit capacity factors decrease, but then it becomes unclear which units are then dispatched to provide the power when these NGCC units have hit their limits. If NGCC units become base load units, utilities will likely need to build even more gas-fired units to operate as load following and peaking units, especially with the increase in RE generation contemplated by Building Block 3, but building 142 143 2012 NGCC Plant Capacity Factor Doc. No. EPA-HQ-OAR-2013-0602-0250. Id. at 3-15. 80 these new units will take time, require approvals, and will put additional strains on the gas supply, pipeline infrastructure, and electric transmission grid. The EPA does not address these issues. Finally, the EPA has failed to adequately consider the time it takes to build the additional natural gas infrastructure necessary to support the 70 percent NGCC capacity factor target in its BSER determination. According to the proposed schedule, the EPA will be approving, or disapproving, state plans between mid-2017 and mid-2019. Compliance with the proposed interim goals begins in 2020.144 Presuming a state plan is approved, there will be one to three years to come into compliance with the state plans. The Energy Information Administration (“EIA”) estimates that an interstate natural gas pipeline takes approximately three years to complete between announcement and completion. There may be additional time necessary to identify the need for additional pipeline and other prior planning actions by the pipeline operator. In individual circumstances, due to localized siting and permitting issues, construction may take even longer. The EPA has not considered the inadequate time their plan allows for the build-out of additional natural gas pipeline infrastructure when establishing a 70 percent capacity factor in Building Block 2. In summary, the EPA has failed to demonstrate that its Building Block 2 target of redispatching generation from existing coal- and oil/gas-fired steam EGUs to existing NGCC units up to an overall NGCC capacity factor of 70 percent for every unit by 2020 is adequately demonstrated or achievable. The Agency failed to assess whether the subset of NGCC units operating at or above a 70 percent capacity factor in 2012 is representative of the remainder of 144 The EPA’s 2020 interim goals assume that Building Block 2 is fully implemented in 2020. Therefore, it is incumbent upon the EPA to demonstrate that the natural gas infrastructure necessary to operate all existing and under construction NGCC units at a 70% capacity factor in 2020 will be in place. The Agency has not made such a demonstration. 81 existing NGCC units, and it did not properly address economic, technical, regulatory, or infrastructure constraints preventing some units from operating at the target level. The EPA also failed to consider the need for additional natural gas pipeline infrastructure to support an overall NGCC capacity factor of 70 percent beginning in 2020. In its October 30, 2014 NODA, the EPA suggests a way to reduce the negative consequences of requiring an interim goal would be to phase-in Building Block 2 over time rather than assuming full redispatch by 2020.145 Duke Energy strongly believes it is inappropriate to require that the Building Block 2 redispatch be fully implemented by 2020. To address this problem the EPA should allow the states to determine how quickly Building Block 2 may be phased in. B. The EPA Erred in its Calculation of NGCC Capacity Factors. In its calculation of NGCC capacity factors, the EPA improperly used net MWh generation divided by nameplate capacity for its evaluation of Building Block 2 NGCC redispatch opportunities.146 This approach is not an appropriate calculation of capacity factors. Net capacity reflects the maximum output that generating equipment can supply to system load, and it is typically lower than nameplate capacity because it reflects capacity reductions due to electricity use for station service or auxiliary loads such as emission control technology. Net MWh generation divided by nameplate capacity conflates a measure of net generation with gross capacity and is not an acceptable metric. Capacity factors should be properly calculated by dividing a unit’s net MWh generation by its summer net capacity because net capacity is the 145 146 79 Fed. Reg. at 64,545. GHG Abatement Measures TSD, page 3-6. 82 indicator of the amount of NGCC capacity available for redispatch purposes because it reflects the amount of energy that these units will actually be able to supply to the power grid. The EPA states in its GHG Abatement Measures TSD that it used nameplate capacity instead of net capacity because hour/minute net capacity data are not reported. 147 While the EPA is correct that net capacity is not reported by the hour/minute, this is not justification for the EPA to have calculated capacity factors as it did. Net capacity data are reported in EIA Form 860 for the vast majority of NGCC units, and the EPA should have used these data in its evaluation of NGCC redispatch opportunities instead of nameplate capacities. The EPA’s use of nameplate capacity in its Building Block 2 NGCC redispatch calculation means that in order to support the levels of redispatch assumed in EPA’s proposed state goals, NGCC units would have to operate at statewide average capacity factors of 80 percent and above when accounting for operational reality — much higher than the alreadyinflated utilization level of 70 percent that EPA assumes, but fails to demonstrate is achievable. For example, in Florida, the difference in available generation for redispatch from 70 percent utilization of all NGCC units in the state based on the summer net capacity of 23,784 MW versus their existing nameplate capacity of 29,485 MW is 35,054,309 MWh. The average annual capacity factor of all NGCC units in Florida would need to reach 87.0 percent to produce this amount of generation. The average capacity factor of NGCC units in North Carolina would need to be 81.1 percent to produce the number of MWh the EPA has assumed for Building Block 2 redispatch for the state. Because these values are statewide averages and many units cannot reach such high levels of utilization, many NGCC units would have to operate at even higher annual capacity factors, levels that simply are not sustainable. 147 Id. 83 While the EPA has failed to demonstrate that its Building Block 2 target of re-dispatching existing NGCC units up to an overall capacity factor of 70 percent by 2020 is adequately demonstrated or achievable, what the EPA really must demonstrate is that re-dispatching existing NGCC units to a much higher capacity factor, in the 80 percent or higher range, based on the use of summer net capacity and a proper calculation of capacity factors, is adequately demonstrated or achievable and can be accomplished by 2020. The Agency has not made such a demonstration. The EPA uses summer net capacities in its IPM modeling, so it is not clear why it chose to use nameplate capacity in this instance. The EPA has failed even to acknowledge the implications of its use of nameplate capacity rather than net capacity, despite the fact that an accurate assessment of the existing NGCC capacity actually available for redispatch is essential to developing an achievable Building Block 2 redispatch target. The EPA should use summer net capacity when analyzing and applying Building Block 2, in order to correctly reflect existing NGCC generating capacity and the level of NGCC utilization that would be necessary to fully compensate for displaced generation from other sources. C. The EPA Should Reaffirm its Proposal to Exclude Gas Co-Firing or Conversion of Coal-fired EGUs as Part of BSER. The EPA has proposed to exclude natural gas co-firing or natural gas conversion at coalfired EGUs as part of BSER.148 However, despite the fact that the EPA’s own economic analysis “. . . suggests that there are more cost effective opportunities for coal-fired utility boilers to reduce their CO2 emissions than through natural gas conversion or co-firing,”149 the EPA solicits 148 149 Id. at 34,875. Id. 84 comment on whether gas conversion or co-firing at coal-fired EGUs should be considered part of BSER.150 Because both the natural gas co-firing and conversion options would be considered redefining the source, which the CAA does not authorize the EPA to do, neither option can be considered part of BSER. Questions of statutory authority aside , the EPA states in the proposal that it “believes that there are a number of factors that warrant further consideration in determining whether the option should be included.”151 None of the factors the EPA mentions in the proposal, however, change the fundamental fact that based on EPA’s own economic analysis, gas co-firing and coal-to-gas conversion are very expensive options that disqualify them from being a part of the Agency’s BSER determination. Just because “. . .a number of utilities have reworked some of their coal-fired units to allow for some level of natural gas co-firing (and in some cases have converted the units to fire entirely on natural gas),”152 is no justification for the EPA to consider that either option is applicable for all coal-fired EGUs and should be a part of its BSER determination. The conditions under which natural gas conversion or co-firing would even be considered a potentially economic option is site specific and highly dependent upon other things such as, the proximity of a coal-fired EGU to an adequate gas supply. The proximity of gas supply to coalfired EGUs is highly variable across the country, with many EGUs being hundreds of miles away from adequate pipeline capacity. Therefore, the cost of the pipeline that would be required to 150 Id. at 34,876. Id at 34,875. 152 Id. 151 85 deliver gas to every coal-fired EGU across the country is highly variable.153 This variability across the fleet of coal-fired EGUs disqualifies gas co-firing or conversion from BSER consideration. Also, the EPA has already determined that co-firing and conversion are very expensive options for reducing CO2 emissions from coal-fired EGUs without considering the cost of new gas pipeline. The added cost of the pipelines would make both options even more expensive, thus further disqualifying them from BSER consideration. Duke Energy is in the process of completing a coal-to-gas conversion at one of its coalfired generating units in South Carolina. The conversion is economically feasible only because the unit was originally designed to accommodate natural gas as a fuel and because an adequate natural gas supply is already available at the site. The conversion is being made entirely for its capacity value. The converted unit is not expected to run except perhaps on a very limited basis during periods of high electricity demand. The conversion would not have been economically attractive had the gas supply not already been on site. Duke Energy would never consider converting any coal-unit to gas for any reason other than its capacity value because a coal unit converted to gas would not be able to compete with more efficient NGCC units. While gas co-firing could potentially be an economically viable option for some coal units, if an adequate gas supply is already available, the number of coal units that have gas on site is limited. Installing a new gas pipeline specifically to support gas co-firing would generally 153 Table 5-22 from Chapter 5 of the Documentation for EPA’s Power Sector Modeling Platform v. 5.13 shows the miles of new pipeline required to hook up coal units, the cost of the new pipeline, and the cost of new pipeline per KW of coal capacity. Miles of new pipeline required range from less than 1 mile to more than 700 miles. The cost of new pipeline (2011$) ranged from a few hundred thousand dollars to more than $500 million. Table 5-22 is available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev513.html. 86 not be economically viable. Therefore, the fact that a co-firing option is limited in its applicability disqualifies it from BSER consideration.154 The EPA rejected proposing natural gas co-firing as BSER for modified and reconstructed coal-fired EGUs. The Agency noted that: While conversion to or co-firing with natural gas in a utility boiler is a technically feasible option to reduce CO2 emission rates, it is an inefficient way to generate electricity compared to use of an NGCC and the resultant CO2 reductions are relatively expensive. The EPA found costs for natural gas co-firing to range from approximately $83/ton to $150/ton of CO2 avoided. Even for cases where the natural gas could be co-fired without any capital investment or impact on the performance of the affected facility (e.g., an existing IGCC facility that already has a sufficient natural gas supply), the costs of CO2 reduction would still be approximately $75/ton of CO2 avoided.155 If the EPA has determined that co-firing is inappropriate as BSER for modified and reconstructed Subpart Da units, which pursuant to section 111(a)(2) are deemed to be new units, it certainly cannot be deemed to be BSER for existing Subpart Da units. In summary, Duke Energy agrees with the EPA that natural gas conversion and co-firing are not BSER for coal-fired EGUs. Sources, however, should have the option to voluntarily use these measures to comply with CO2 emission standards. Natural gas conversion and co-firing are extremely costly options for reducing CO2 emissions and are only potentially appropriate for a limited number of coal-fired EGUs based on site-specific factors. Despite the EPA’s own analysis finding that natural gas co-firing at coal-fired EGUs is not economically justified as BSER, in its October 30, 2014 NODA, the EPA again solicits 154 Table 5-23 from Chapter 5 of the Documentation for EPA’s Power Sector Modeling Platform v. 5.13 lists the coal plants to which the EPA makes a 10% gas co-firing option available in its power sector modeling. These are plants where the EPA has concluded that have gas on site based on available data. The EPA assumes that the supply is adequate to support 10% co-firing. The universe of plants in Table 5-23 totals just over 105,000 MW of capacity. This compares to the total capacity of all coal plants shown in Table 5-22 of greater than 285,000 MW. Table 5-22 and 5-23 are available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev513.html. 155 79 Fed. Reg. at 34,982/2. 87 comments on “ways that building block 2 could be expanded to include . . .natural gas co-firing in existing coal-fired boilers.”156 Natural gas co-firing has not been adequately demonstrated for the source category as a whole, and the EPA has failed to provide any justification for any such determination. The fact that owners or operators of certain individual coal-fired EGUs have determined co-firing to be feasible and economic for their individual situation does not imply by any stretch of the imagination that co-firing is an adequately demonstrated system of emission reduction. The EPA should therefore abandon any consideration of including natural gas cofiring as BSER. D. Miscellaneous Building Block 2 Issues. 1. The EPA Has Provided No Technical Justification For Using MWh From Increased Utilization of NGCC Units to Decrease Generation From Coal Units Before Decreasing Generation From Oil/Gas Steam Units. The EPA specifically requests comment on whether it should use MWh from the increased utilization of NGCC units in Building Block 2 to decrease generation from a state’s coal-fired EGUs before decreasing generation from the state’s oil/gas-fired steam units.157 In its proposed application of Building Block 2 in BSER, the EPA applied the MWh from increased utilization of NGCC units proportionately to a state’s coal-fired and oil/gas-fired steam units. Clearly, if the EPA were to apply the method on which it seeks comment, it would “maximize the resulting emission reductions.”158 However, this hardly seems justified and the EPA neglects to provide technical analysis for this alternative approach. Without providing a technical justification for the alternative approach the EPA has no sound basis for adopting it. Simply wanting to maximize emission reductions is not a justification for the change. Central to 156 79 Fed. Reg. at 64,545. 79 Fed. Reg. at 34,897. 158 Id. 157 88 this dilemma is the fact that the EPA has no authority to dictate which units are dispatched first, last, or otherwise. Clearly, the EPA is attempting to force state environmental agencies to usurp the authority for dispatch decisions which are made by utilities and independent system operators with oversight by state utility commissions and the Federal Energy Regulatory Commission. The decision making authority to increase the capacity factor of NGCC units as well as whether to dictate whether reductions come first from coal generation or oil/gas generation is based on a number of factors and clearly does not belong to EPA and therefore should not be considered. 2. Duke Energy Supports the EPA’s Proposal to Exclude New NGCC Capacity As a Component of BSER for Building Block 2. The EPA has proposed to exclude new NGCC capacity as a component of BSER and therefore does not propose to include new NGCC capacity in establishing state goals. The Agency does, however, invite comment on whether it should consider construction and use of new NGCC capacity as part of the basis supporting the BSER, and on ways to define appropriate state-level goals based on consideration of new NGCC capacity.159 Duke Energy believes the EPA is correct to exclude new NGCC capacity as a component of its BSER and therefore exclude such capacity in establishing state goals. As EPA correctly notes, new NGCC capacity will be regulated under section 111(b).160 The EPA cannot simultaneously treat the same capacity as an existing unit under section111(d)161. In fact, if the EPA were to include new NGCC as a component of BSER and include it in state goal calculations, it would, in effect, be treating that capacity as existing before it is even built, which clearly does not make sense. In addition, given the fact that the EPA does not propose to include 159 79 Fed. Reg. at 34,877. Id. at 34,904. 161 Refer to section III above for further discussion of why the EPA cannot simultaneously regulate units under section 111(b) and 111(d). 160 89 this option in state goals because it “…believes the cost considerations… indicate a higher cost for CO2 reductions achievable from redispatch to new NGCC capacity than for other options…,”162 Duke Energy does not see how the EPA could then justify disregarding that finding and including new NGCC capacity as a BSER component. Furthermore, it would not be reasonable for the EPA to attempt to include new NGCC capacity as a component of BSER and include it in state goals because of the tremendous uncertainty regarding new NGCC development. It is simply not possible to accurately determine what new NGCC capacity would be built in each state. Relying on announcements of new capacity builds would be inaccurate because not everything that is announced actually gets built. The use of modeling also would not be an appropriate tool. Modeling results are not only influenced by numerous uncertain and highly variable input assumptions but the use of modeling would be inconsistent with the EPA’s decision to use a historic baseline for calculating state goals. In addition, it is unclear how far into the future the EPA would propose to estimate the amount of new NGCC to include. Since the EPA has proposed a program that begins in 2020 and extends into the future indefinitely, the Agency would need to determine a cutoff year in order to identify the amount of new NGCC capacity to include in any state’s goal. That year could be 2020, 2030, or any single other year, as the cutoff year selected would ultimately be arbitrary. Finally, while Duke Energy does not believe the use of increased utilization of NGCC units as a component of the BSER determination for regulating existing coal-fired EGUs is permissible under the CAA, it is an even more preposterous to include some highly uncertain and arbitrary amount of future NGCC capacity as a component of BSER for setting emission limits for existing coal-fired EGUs. 162 Id at 34,877. 90 The EPA’s October 30, 2014 NODA solicits comment on “ways that building block 2 could be expanded to include new NGCC units. . . in existing coal-fired boilers.”163 The EPA’s discussion suggests that BSER should be based on “the cost and feasibility of the total amount of natural gas used, as opposed to the extent to which the gas is used for particular types of generation (i.e., existing NGCC generation, new NGCC generation, or co-firing).” 164 The EPA claims that requiring new NGCC as part of the BSER would be “more consistent with historic NGCC deployment, better reflect growing geographic availability of natural gas supply, contribute to expanded generation fuel diversity in states that currently have relatively little NGCC capacity, and offer more cost-effective emission reductions.”165 Under this new approach, raised for the first time in the NODA but not formally proposed, in addition to shifting generation from existing coal-fired units to existing NGCC units until the NGCC units reach a 70% capacity factor, Building Block 2 would also assume “some minimum value as a floor for the amount of generation shift for purposes of Building Block 2, whether such a shift were to take the form of redispatch from steam generation to existing NGCC units, redispatch to new NGCC units, or co-firing natural gas in existing coal-fired boilers.”166 The EPA has no authority to impose federally enforceable obligations on new sources (such as new NGCC units) under section 111(d). Nor does the EPA have authority under section 111(d) to require the construction of any new source. Section 111(d) applies only to existing sources, which the CAA defines to be mutually exclusive of new sources. The EPA incorrectly suggests that constructing a new NGCC unit can be considered to be a “system of emission 163 79 Fed. Reg. at 64,545. Id. at 64,550. 165 Id. 166 Id. at 64,550. 164 91 reduction” under section 111,167 but a “system of emission reduction” is limited to activities that can be implemented at the source itself. The approach the EPA discusses would require owners to go beyond the source itself and construct an entirely new source to replace it. The EPA should abandon any consideration of including new NGCC units as part of a BSER determination. 3. States Should Have Discretion to Include New NGCC Emissions and Generation When Demonstrating Compliance Under a Rate-Based Program. The EPA requests comment on how emissions changes under a rate-based plan resulting from substitution of generation by new NGCC for generation by affected EGUs should be calculated toward a required emission performance level for affected EGUs.168 As the EPA correctly points out, “under a mass-based plan where an emission limit on affected EGUs would assure achievement of the required level of emission performance in the state plan, any emission reductions at affected EGUs resulting from substitution of new NGCC generation for higheremitting generation by existing affected EGUs would automatically be reflected in mass emission reductions from affected EGUs. A state would not need to include enforceable provisions for new NGCC in its plan, under such an approach.”169 Under a mass-based approach, emissions from new NGCC would not and should not be accounted for when demonstrating compliance, which is entirely appropriate because new NGCC units would not be affected units under section 111(d). Similar to the mass-based plan approach, a rate-based plan where an emission rate limit on affected EGUs would assure achievement of the required level of emission rate performance 167 79 Fed. Reg. at 64,550. 79 Fed. Reg. at 34,924. 169 Id. at 34,923. 168 92 in the state plan, any emission rate reductions at affected EGUs resulting from substitution of new NGCC generation for higher-emitting generation by existing affected EGUs would also automatically be reflected in any emission rate changes from affected EGUs, and a state would therefore not need to include enforceable provisions for new NGCC in its plan. Under this scenario, like with the mass-based approach described above, emissions and generation from new NGCC capacity would not need to be accounted for when demonstrating compliance. However, while new NGCC units are outside of the section 111(d) program, to the extent these newly constructed NGCC units displace higher-emitting generation units, states should be given wide latitude to decide how to address new NGCC for purposes of calculating compliance. It would be permissible for a state that employs the rate-based approach under section 111(d) to allow the megawatt hours generated by newly constructed NGCC units to be included in the denominator for a state’s rate calculation. This approach would be similar to how renewable energy and new nuclear units are treated under the Proposed Guidelines. VII. Building Block 3 A. Issues Related to the EPA Proposed State Renewable Energy Targets. 1. The EPA Inappropriately Set the State Renewable Energy Targets Used in the State Goal Calculations. Reiterating the point made earlier, Duke Energy does not believe a section 111(d) BSER determination can rely on beyond-the-source measures such as RE. If the EPA determines they will include RE in setting State targets, it should address important problems in the calculation of these targets by addressing the following points: a) EPA’s Use of State Renewable Portfolio Standards To Develop Regional RE Targets is Not Appropriate. The EPA presumes that existing state Renewable Portfolio Standards (RPS) are based on a reasoned determination regarding the renewable energy endowment and affordability of RE 93 within a state, but then assumes that states without an RPS can take on the same RPS as that of nearby state(s) in the geographic regions defined by the EPA. The EPA explains “states have already had the opportunity to assess those [RPS] requirements against a range of policy objectives including both feasibility and costs. These prior state assessments therefore support the feasibility and costs of the best practices scenario as well. Second, renewable resource development potential varies by region, and the RPS requirements developed by the states necessarily reflect consideration of the states’ own respective regional contexts.”170 If one were to follow this thread to its logical conclusion, those states without an RPS requirement could be said to have made the determination that there is no affordable RE resource to exploit within their state. Therefore, rather than using the RPS of one or two states in a broad geographic region to determine the level of renewables that should factor into each a state’s CO2 reduction target, the EPA should restrict itself to using only the existing RPS level of the state itself. For states with an existing RPS, the Building Block 3 RE target should not exceed their RPS requirement. States without an RPS should be seen as having no RE Building Block. b) EPA Should Recalculate Certain State RPS Targets to Correct For Erroneous Assumptions. Building Block 3, using existing State RPS targets to determine the amount of RE incorporated into the state goal calculations, overlooks the fact that some RPS programs include energy efficiency, out of state RE certificates (“RECs”) without energy delivered into the State (unbundled RECs), or carbon capture and sequestration (“CCS”) as a qualifying source of RECs (a combination of two separate building blocks). Some states also specify a limit on the amount of imported (RECs) that are unbundled from power, thereby having no impact on in-state power generation. A state which indicates a maximum amount of unbundled RECs that can be used for 170 79 Fed. Reg. at 34,866. 94 compliance has demonstrated a concern that without such a limit, utilities are likely to comply with the RPS by buying less costly RECs from out of State, rather than building renewables in State. The limit on the use of unbundled out of State RECs conversely specifies the level of required renewable energy that must be produced in State. (1) Correct Interpretation of the North Carolina RPS. North Carolina allows utilities to use energy efficiency programs to comply with 40 percent of the final State RPS requirements, and unbundled RECs to comply with 25 percent of the program, thereby reducing the amount of RE that must be produced in -state. This is North Carolina’s determination of the feasible level of RE that can be deployed within the state.171 The North Carolina RPS also includes different requirements for investor owned utilities and for Public Owned Utilities such as Municipal and Cooperatively-owned utilities.172 Combined, these factors significantly decrease North Carolina’s final top line RE requirement from 12.5 percent to 4.85 percent. The following table shows the actual amount of required in-State RE generation after adjusting for the energy efficiency and REC provisions in the North Carolina RPS, which should be the ceiling on any RE requirement for North Carolina. 171 Under this law, investor-owned utilities in North Carolina will ultimately be required to meet up to 12.5% of their energy needs through renewable energy resources or energy efficiency measures in 2021. The law allows that up to 40% can be met through Energy Efficiency and up to 25% can be met via purchase of Renewable Energy Certificates produced out of State. See § 62-133.8.(b)(2)c and e. There is no limit on the amount of RECs that Dominion Energy can use to comply with the 4% of the NC market they serve. http://www.ncga.state.nc.us/EnactedLegislation/Statutes/HTML/BySection/Chapter_62/GS_62-133.8.html 172 See § 62-133.8.(c)(2)d http://www.ncga.state.nc.us/EnactedLegislation/Statutes/HTML/BySection/Chapter_62/GS_62-133.8.html. 95 Entity Type NC Utilities NC Coops/ Munis Total Electricity Load % of total Dominion Load (served by out of state gen) 95,391,119 75% 4,114,548 31,513,009 25% 2012 load (MWh) In State Utility Target In State target corrected for Dominion Exemption [5%(5%*Dom Load/Total Utility Load)] 4.19% 40% EE ceiling Historic RPS compliance via EE RPS less EE Carve out 25% unbundled REC ceiling (no power delivered to remaining load) 12.5% 5% - 7.50% 3.13% 4.38% 10% - 0.64% 9.36% 2.50% 6.86% 2021 RPS 173 State Weighted Average RPS for Investor Owned Utilities and Munis/C OOPs 4.85% 126,904,128 The North Carolina RPS value of 4.85 percent, when inserted in the TSD Spreadsheet174 used to determine regional targets, results in a change in the South East region’s requirement from 10 percent to 4.85 percent. (2) Corrections to Minnesota’s RPS. In its consideration of the Minnesota RPS, the EPA fails to consider that the state actually has three different RPS requirements: one for Xcel Energy; one for other investor owned utilities in the state; and one for the state’s municipal utilities and cooperatives.175 The recalculated RPS for the state, adjusted for these factors, is 25 percent. The following table shows how the state’s three RPS requirements should be applied to arrive as the correct RPS target for Minnesota. 173 Duke Energy believes it is more appropriate to use the final 2021 North Carolina RPS requirement than the 2020 requirement, which is different. 174 20140602tsd-proposed-re-approach spreadsheet http://www2.epa.gov/sites/production/files/201406/20140602tsd-proposed-re-approach.xlsx. 175 See http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=MN14R&re=1&ee=1. 96 Xcel Non-Xcel Non-IOUs Total Weighted Avg. Requirement 2020 RPS Requirement 30% 20% 20% 2012 MWh Sales 31,183,575 9,388,538 27,416,422 67,988,535 2020 RE Requirement 9,355,073 1,877,708 5,483,284 16,716,065 25% This corrected Minnesota RPS value, when inserted in the TSD Spreadsheet176 used to determine regional targets, results in a change in the North Central region’s requirement from 15 percent to 14.1 percent. (3) Correction to the Ohio RPS. On June 13, 2014, Ohio Governor Kasich signed Senate Bill 310, which froze the state’s RPS targets for two years. The freeze results in a change to the 2020 target from 10 percent to 6.5 percent.177 Before passage of S.B. 310, the Ohio Alternative Energy Standard required that 50 percent of the RE used to comply with the State Alternative Energy Standard were to be produced inside the State, indicating there was some doubt whether or not the Standard would be met with in-State resources absent such a provision. In addition to freezing the Ohio program for two years, Senate Bill 310 lifts the procurement restriction, allowing unbundled RECs procured from anywhere in the country to be used to comply with the state Standard. While this recent revision could mean that zero is the appropriate level of affordable RE available within Ohio, Duke Energy believes it is reasonable to interpret the previous 50 percent procurement requirement as limiting the 2020 level of affordable RE available to a maximum of one-half of 176 20140602tsd-proposed-re-approach spreadsheet http://www2.epa.gov/sites/production/files/201406/20140602tsd-proposed-re-approach.xlsx. 177 http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=OH14R 97 the overall 6.5 percent requirement, which is 3.25 percent for available and competitive renewable energy in the State of Ohio. This corrected Ohio RPS value, when inserted in the TSD Spreadsheet178 used to determine regional targets, results in a change in the East Central region’s requirement from 16 percent to 14.9 percent. (4) Changes to the Amounts of RE Used in State Goal Calculations After Incorporating Above Corrections. Duke Energy incorporated the above changes into the Technical Support Document (TSD) spreadsheet used to calculate the state targets179 by changing the effective RE level for North Carolina, Ohio and Minnesota on the “Input – Effective RE Level” tab. The revised renewable energy targets as recalculated by the TSD spreadsheet for the states served by Duke Energy are shown below in the column headed “Revised 2030 RE Generation Targets as Percent of Total Generation.” 178 20140602tsd-proposed-re-approach spreadsheet http://www2.epa.gov/sites/production/files/201406/20140602tsd-proposed-re-approach.xlsx. 179 http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-proposed-re-approach.xlsx. 98 2020 Nominal State RPS North Carolina South Carolina Florida Indiana181 Ohio Kentucky Minnesota 12.5%180 None None None 6.5%182 None 30% Assigned RE Regional Generation Target Suggested Level of Revised Regional RE target if use Regional RPS average based on Corrected RPS level EPA Proposed 2030 RE Level for each state 4.85% 10% 4.85% 10% 4.85% NA 10% 4.85% 10% 4.85% NA NA 3.25%183 NA NA 10% 15% 16% 10% 15% 4.85% 14.1% 14.9% 4.85% 14.1% 10% 6.6% 10.6% 1.9% 15.1% 4.85% 6.1% 10% 0.9% 14.1% 202021 RPS modified to include only in-state produced RE and exclude Energy Efficiency allowed to meet the state RPS Revised 2030 RE Targets as Percent of Total Generation 2. The EPA Should Exclude Soon to Expire Federal Tax Incentives When Evaluating the Cost of RE. The EPA notes the impressive cost reductions achieved by RE technologies in recent years and the fact that levelized purchased power agreement (“PPA”) prices have achieved levels competitive with conventional generation resources. But PPA prices are not an appropriate measure of the competitiveness of different technologies as they do not account for costs hidden or obscured by government subsidies such as Production Tax Credit or Investment Tax Credits. For example, the Production Tax Credit allows developers of wind RE to offer PPAs at a 180 For North Carolina used the final 2021 State requirement instead of 2020. Indiana’s target shifts due to a changed regional number that reflects correction of the Minnesota RPS to reflect different requirements for different utilities. The MN RPS number is therefore reduced from 30% to 25%. See: http://www.dsireusa.org/rpsdata/RPSspread042213.xlsx. 182 Ohio passed S.B. 310 in the summer of 2014, delaying the increase in Ohio’s required level of Alternative Energy for two years, changing the 2020 requirement to 6.5%. See: http://www.legislature.state.oh.us/bills.cfm?ID=130_SB_310. 183 The Ohio rule previously required that 50% of the renewable energy be produced within the state – the remaining 50% can be covered through renewable credits purchased out of state. This indicated Ohio policymakers were concerned that without a floor on locally produced renewable energy that most would be procured from out of State – therefore, Ohio policymaker had determined that only half of the nominal standard of 6.5% of energy would likely be produced within the state. See: http://www.puco.ohio.gov/puco/index.cfm/industryinformation/industry-topics/ohioe28099s-renewable-and-advanced-energy-portfoliostandard/#sthash.210Vrehl.dpbs. 181 99 substantial discount to what they would otherwise require if they had to pay for their investment without the tax credits. The EPA would have to make the assumption that the Production Tax Credit for wind and the Investment Tax Credit for solar RE will continue beyond their current congressionally mandated 2016 expiration dates for their claims of competitiveness to be valid. a) Economic Potential of RE Should Be Considered, Not Technical or Market Potential. Section 4.2.2 of the GHG Abatement Measures TSD cites the very large amount of Achievable Renewable Energy Potential in setting targets, noting the large amount of RE (better characterized as the realized Market Potential184) that has been deployed in the United States (“U.S.”) It then compares the amount of solar potential (Technical Potential)185 in the U.S., noting that it is superior to that of Germany, while also noting Germany has a much higher use of solar (realized Market Potential) than the U.S. The EPA provides this information supposedly in an effort to demonstrate that the U.S. can easily achieve a much greater amount of RE production. The EPA then mistakenly compares the calculated RE targets (imposed Market Potential) for each state to the RE Technical Potential of each state, showing that the targets are a very modest percentage of the Technical Potential – by definition this would almost always be true 184 From the IPCC’s Fourth Assessment Report http://www.ipcc.ch/publications_and_data/ar4/wg3/en/ch2s2-4-31.html:“Market potential’ indicates the amount of GHG mitigation that might be expected to occur under forecast market conditions, including policies and measures in place at the time. It is based on private unit costs and discount rates, as they appear in the base year and as they are expected to change in the absence of any additional policies and measures. In other words, as in the TAR, market potential is the conventional assessment of the mitigation potential at current market price, with all barriers, hidden costs, etc. in place. The baseline is usually historical emissions or model projections, assuming zero social cost of carbon and no additional mitigation policies. However, if action is taken to improve the functioning of the markets, to reduce barriers and create opportunities (e.g. policies of market transformation to raise standards of energy efficiency via labelling), then mitigation potentials will become higher.” 185 The ‘technical potential’ is the amount by which it is possible to reduce greenhouse gas emissions or improve energy efficiency by implementing a technology or practice that has already been demonstrated. There is no specific reference to costs here, only to ‘practical constraints’, although in some cases implicit economic considerations are taken into account. Finally the ‘physical potential’ is the theoretical (thermodynamic) and sometimes, in practice, rather uncertain upper limit to mitigation, which also relies on the development of new technologies.” 100 except for the most extreme targets and is therefore a meaningless observation. The EPA should not use the Technical Potential as a comparison point, nor as will be discussed later, as an input to the determination of the targets in the RE Alternative Proposal, because almost by definition the Technical Potential is never expected to be realized in any scenario as it does not consider costs or other barriers to resource development, but only the physical potential for deployment. A more appropriate approach would be for the EPA to compare RE targets to the “Economic Potential” of RE, which is defined in the IPCC’s Fourth Assessment Report as follows:186: …‘economic potential’ is defined as the potential for cost-effective GHG mitigation when non-market social costs and benefits are included with market costs and benefits [emphasis added] in assessing the options[17] for particular levels of carbon prices in US$/tCO2 and US$/tC-eq. (as affected by mitigation policies) and when using social discount rates instead of private ones. This includes externalities (i.e. non-market costs and benefits such as environmental co-benefits).…” b) The EPA Misunderstood the Lawrence Berkeley National Laboratory Study – A Large Deployment of RE Will Cause Larger Price Increases Than Cited in the LBNL Study. In Section 4.3 of the GHG Abatement Measures TSD the EPA claims ample availability and affordability of new RE generation and concludes that increasing RE generation would not noticeably increase power prices.187 The EPA notes a 2007 Lawrence Berkeley National Laboratory (“LBNL”) study that examined other studies of RE and its costs. The LBNL study indicated that existing State RPS requirements have caused average rate increases of approximately 0.7 percent. However, the use of this study is inappropriate as it merely synthesized work by others without any quality criteria for what studies were included, whether 186 IPCC’s Fourth Assessment Report http://www.ipcc.ch/publications_and_data/ar4/wg3/en/ch2s2-4-3-1.html. EPA, TSD for Carbon Pollution Guidelines for Existing Power Plants: Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary Sources: Electric Utility Generating Units, Sect 4.3. 187 101 they were peer reviewed or whether they used appropriate, analytically vetted tools to perform the analyses.188 Of the 28 studies included in the LBNL work, sixteen were sponsored by foundations and non-governmental organizations (“NGOs”) with a clear agenda to promote RE, with ten of these studies actually performed by these same issue-oriented NGOs.189 The EPA fails to note these studies covered what were then the early years of the State programs in which the RPS requirements were fairly modest (in the low single digits). Most State programs do not require significant renewable energy deployment until the post 2020 timeframe. A small percentage requirement of a new generation resource, even if very costly, will not drive very large price increases, as the increased costs are spread over a large amount of electricity load. It is only as the percentage requirement grows over time that the greater expense of the resource begins to make a noticeable impact on retail power prices. This is borne out by evidence the EPA cites from a subsequent LBNL study conducted only three years after the first LBNL study which showed that electricity price increases in states with RPS had grown to approximately 2 percent - at a time when most state RPS requirements were still in the single digits. The following simple example demonstrates how, as RE requirements increase, ratepayer prices will increase noticeably and why current penetration levels and associated rate increases are meaningless predictors of expected rate increases with greater renewable energy penetration rates. 188 189 http://emp.lbl.gov/sites/all/files/PRESENTATION%20lbnl%20-%2061580-ppt.pdf. Id. at 7. 102 Conventional Energy Cost Renewable Energy Cost Conventional Energy % Renewable Energy % Weighted Avg. Cost $100.00 $130.00 100% 0% $100.00 90% 10% $103.00 80% 20% $106.00 50% 50% $115.00 0% 100% $130.00 c) The LBNL Study Cited by the EPA Does Not Demonstrate that RE is a Cost Effective Means to Lower CO2 Emissions – Analysis Using Energy System Models Show Cost of CO2 Reductions From RE Exceed $50/ton. The EPA uncritically notes that the first LBNL study190 discussed in the previous section of these comments produced a median cost per ton of CO2 avoided of approximately $3,191 having not noticed that those cost/ton included in the meta-study that were less than $5 came exclusively from the advocacy groups’ studies (several of these group’s studies actually claimed negative costs).192 The advocacy groups’ analyses were seriously flawed because they relied on simple spreadsheets rather than more complete integrated energy system modeling tools that are the standard in analyzing avoided costs used by utilities and regulators. The studies which employed the standard energy system models produced avoided cost figures that were much higher than the median price cited by the EPA. The studies from the non-advocacy groups that used integrated energy system models produced cost/ton of avoided CO2 directionally in line with studies done by the academic community,193 with cost per ton of CO2 reduction between $50 and $181. Therefore, the EPA should not rely on the LBNL study as an indicator of the 190 http://emp.lbl.gov/sites/all/files/PRESENTATION%20lbnl%20-%2061580-ppt.pdf, page 19. TSD GHG Abatement Measures, Sect 4.3 192 http://emp.lbl.gov/sites/all/files/PRESENTATION%20lbnl%20-%2061580-ppt.pdf, page 19 193 Marcantonini, C and Ellerman, D (2013), The Cost of Abating CO2 Emissions by Renewable Energy Incentives in Germany, Climate Policy Research Unit, European University Institute, Italy, February 1, 2013 as part of the MIT Center for Energy and Environmental Policy Research http://web.mit.edu/ceepr/www/publications/workingpapers/2013-005.pdf 191 103 costs of RE generation, the projected impact on electricity rates, or the costs per ton of CO2 reductions created. In citing Germany as an example of an effective RE program, the EPA provides a helpful opportunity to look at the cost effectiveness of RE programs in lowering CO2 emissions, especially in regions with relatively modest technical potential. Germany has indeed achieved the extraordinary level of 6 percent of power generation from wind and solar RE resources as cited in the GHG Abatement Measures TSD194. However, the CO2 reductions driven by the policy have been extremely expensive, especially relative to CO2 market prices in the European Union – Emission Trading System (“EU-ETS”), which have hovered around €10/ton. Studies indicate that the CO2 reductions from the solar component of the German program cost approximately €537/ton for the period of 2006 to 2010.195 The same study noted CO2 reductions from wind cost approximately €43/ton. The German RE program has forced the creation of these very expensive €537/ton CO2 reductions when equivalent reductions could have been created at a cost slightly more than the EU-ETS market prices in the range of €10/ton. Rather than supporting the proposition that a RE requirement is a desirable and affordable means to lower CO2 emissions from the power sector, the German experience demonstrates conclusively that RE requirements are among the most costly ways to lower CO2 emissions. Finally, the EPA’s claim that wind and solar are competitive with conventional power sources196 fails to consider recent papers from MIT197 and Brookings.198 These papers 194 GHG Abatement Measures TSD, Docket ID No. EPA-HQ-OAR-2013-0602, Section 4-7, at 4-8. Id. at 20. 196 GHG Abatement Measures TSD, Docket ID No. EPA-HQ-OAR-2013-0602, Section 4-7. 195 104 demonstrate that when the required amount of back up generating capacity is included in cost calculations, that wind and solar remain among the most costly energy resources, even after the inclusion of externalities. In fact, most existing wind and solar energy resources were constructed not because they were the low cost means to lower CO2 emissions or to produce energy, but to comply with or take advantage of policies created to satisfy other objectives (interest group technology preference, employment, energy security, etc.). The table below is from the Brookings’ paper cited in the preceding paragraph and shows the CO2 prices that would be required to cause wind and solar investments to be a “break even” proposition for utilities at a natural gas price of $4.33 per million Btus. In the table, “Net Benefits” is defined as cost minus benefits of the particular technology used instead of coal after assigning a CO2 price to the fossil fueled units emissions. For example, if the CO2 price is $50, neither wind nor solar create a net benefit, while hydro and nuclear and NGCC units create significant value. The analysis demonstrates that a coal-fueled EGU would not be displaced by wind absent a CO2 price of at least $61.87, while solar would require a CO2 price of at least $185.84. The CO2 prices from the Brookings paper are consistent with the non-advocacy-groups’ studies cited in the previously discussed LBNL meta-study which showed CO2 abatement costs from renewables between $50 and $181/ton. 197 "Comparing the Costs of Intermittent and Dispatchable Electricity-Generating Technologies", by Paul Joskow, Massachusetts Institute of Technology, September 2011. 198 "The Net Benefits of Low and No-carbon Electricity Technologies", by Charles Frank, Brookings Institution, May 2014. 105 The CO2 price for solar even exceeds the range of policy benefits as calculated in the Social Cost of Carbon199 except for the case that uses a 3 percent discount rate looking at the 95th percentile range of impacts.200 Using the same metric, wind is not an economic choice except in the cases with a 3 percent or lower discount rate, and only after 2035 in the 3 percent case. This latter point would indicate that wind would not be an economic choice to lower CO2 emissions during the pre-2030 timeframe considered in the proposal. This provides further analytical evidence demonstrating that electricity generated from wind and solar do not produce cost effective CO2 reductions and therefore should not be part of the EPA’s BSER determination. (1) EPA should Provide Guidance to States Regarding the Impact of Overlapping and Competing Compliance Mechanisms. The EPA should make clear that if a state were to implement a market-based trading program to limit CO2, care should be taken to ensure that state RPS policies do not compete with the market-based emissions reduction policies by driving very high cost CO2 emission reductions in existing CO2 trading markets. An RPS drives very costly emissions reductions, bypassing 199 While this use of the SCC is appropriate, Duke Energy does have serious concerns regarding the validity of the current SCC calculations which are elaborated on in an EPRI analysis found here: http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?productId=000000003002004657. 200 http://www.epa.gov/climatechange/EPAactivities/economics/scc.html. 106 more cost effective emission reduction options the market would otherwise implement to meet the cap. At the least, the EPA should assist states by making clear the relative costs of different approaches, including the cost implications of layering policies on top of market-based approaches. If the state does not implement a CO2 trading program, an RPS may be considered by some to be necessary. But if a state were to implement a CO2 trading program, it should NOT then implement an RPS, as this can create the distortions cited above and severely harm the cost effectiveness of a market-based emission reduction program. d) The EPA Should Not Set a RE Floor Based on Any Year’s RE Generation. In response to the EPA invitation to comment regarding whether or not to set a RE floor based on reported 2012 RE generation in a state, inclusion of a floor would convert a Building Block into a defined federal RPS. Including a RE floor in the Building Block changes the block into a separate RE mandate. The EPA should be completely indifferent regarding how a state meets the final CO2 emission reduction target and therefore should not include a RE floor. e) The EPA Should Consider the Amount of Fossil Fueled Generation in a State if Setting State RE Targets. In response to the EPA invitation to comment regarding whether a state’s RE target should account for the amount of fossil fuel-fired generation in the state, Duke Energy notes that failing to do so can in some cases create a RE target that is larger than the amount of the state’s 2012 fossil fueled generation. If one assumes additional RE “dilutes” the emissions rate from fossil fueled generators by adding emission free electricity to the grid, and thus displacing power from fossil fueled sources, it would seem to make sense not to set a target that would exceed a state’s 2012 fossil generation. Doing so would mean that the excess RE is displacing other nonemitting generation sources, which needlessly increases the costs of lowering fossil emissions 107 with no noticeable emission benefits. This would needlessly increase total program compliance costs. f) The EPA Should Not Include Hydropower When Setting State Targets. The EPA has excluded generation from existing hydropower from its BSER-related RE generation potential,201 but invites “. . .comment regarding whether to include 2012 hydropower generation from each state in that state’s ‘‘best practices’’ RE quantified under this approach, and whether and how the EPA should consider year-to-year variability in hydropower generation if such generation is included in the RE targets quantified as part of BSER.202 Duke Energy supports the EPA’s decision to exclude existing hydropower from its proposed BSER determination and state goal calculation.203 Existing hydropower should not be included in Building Block 3 and factored into state goal calculations because there is little that can be done to expand electricity production from hydroelectric sources, and as the EPA observes, existing hydropower facilities are geographically limited. In addition, the inclusion of existing hydropower in state goal calculations would introduce additional compliance risk for states with hydropower because the amount of generation from hydropower facilities is subject to year-toyear variability based on among other things, the amount of precipitation a watershed receives. Drought, for example, can limit the amount of generation a hydropower facility can produce, which would make compliance more difficult if existing hydropower were included in state goal calculations. As a practical matter, the ability to comply with a section 111(d) standard of performance should not be influenced by the amount of rain that falls. There are also regulatory 201 79 Fed. Reg. at 34,867. Id. at 34,869. 203 Reiterating the point made earlier, Duke Energy does not believe a section 111(d) BSER determination can rely on beyond-the-source measures such as hydropower. 202 108 requirements placed on hydropower facilities as part of a FERC license that can reduce the amount of electricity hydropower facilities can generate. g) Regulatory Uncertainties Regarding Biomass Energy Need to Be Resolved Before Inclusion in BSER. The various approaches the EPA has proposed to determine state targets consider biomass-based generation to be carbon neutral for the purpose of establishing the state RE goals, but the EPA postpones determination of whether states will be able to consider biomass for compliance purposes until the Accounting Framework for Biogenic Emissions is finalized. The EPA should maintain consistency with state RPS rules and enable all RPS-eligible generation to count towards a state’s compliance determination. The EPA’s primary proposal for setting RE targets relies on existing state RPS programs to develop regional and state RE goals. All states with an RPS include biomass as part of tier 1 eligible renewable resources.204 And for many states, especially those in the Southeast region, biomass constitutes a significant portion of RE generation.205 The EPA averaged state RPS requirements to create regional RE goals without regard to the proportion of compliance expected to come from biomass generation.206 The proposed Alternate Approach also incorporates biomass as a zero-carbon resource. The Alternate Approach uses the technical and economic potential of each of several technology types within each state to determine state RE goals.207 While evaluated slightly differently than 204 205 See DSIRE, “RPS Data Spreadsheet” (2013), http://www.dsireusa.org/rpsdata/RPSspread042213.xlsx. See EIA, “Electricity Data Browser, Net Generation for All Sources” (2013), http://www.eia.gov/electricity/data/browser/#/topic/0?agg=2,0,1&fuel=0208&geo=vvvvvvvvvvvvo&sec=g&freq=A&start=2001 &end=2013&ctype=linechart<ype=pin&rtype=s&maptype=0&rse=0&pin. 206 Confusingly, EPA did not consider biomass generation to be carbon neutral when setting state 2012 fossil generation baseline from which the state goals were built. See Goal Computation TSD at 8. 207 See generally Alterative Renewables Approach TSD. 109 other resources,208 biomass-based generation is one of the RE resources evaluated, and it constitutes a significant portion of the RE MWh that would be incorporated in state goals through Building Block 3.209 Both the proposed and Alternate approaches, therefore, include biomass when determining the stringency of state RE goals. In both cases, biomass is treated as a zero-carbon resource. However, the Proposed Guidelines are not clear on the extent to which states and affected EGUs will be able to utilize the emission reduction benefits of biomass combustion for compliance. The preamble of the Proposed Guidelines includes a discussion of the EPA’s in-progress efforts to develop an “Accounting Framework for Biogenic Emissions.” The EPA Science Advisory Board has reviewed a draft of the framework, and the EPA is in the process of revising the framework.210 The EPA must provide consistent treatment of the emission reduction opportunities of biomass-based generation. The EPA should ensure that in any final rule, any biomass included as part of BSER Building Block 3 is accounted for in the calculation of state goals consistently with how the Agency ultimately allows states to account for that generation as part of compliance. To the extent that biomass is an element of zero-emission generation when calculating state RE goals in the final rule, consistent treatment of biomass for compliance purposes must be allowed. 208 The Proposed Guidelines provide little explanation for the treatment of biomass under the Alternative Renewables Approach. However, it appears that biomass potential is determined only based on IPM-based cost criteria and not technical feasibility. Moreover, EPA appears to only be evaluating existing biomass-based generation. See Alternative Renewables Approach TSD at 3 n.6. 209 See Alternative Renewables Spreadsheet. 210 79 Fed. Reg. at 34,924 to 34,925. 110 h) The First Two Alternatives Provided in the EPA’s Alternative RE Target Approach Are Not Based on Sound Analytics. Duke Energy believes the third approach the EPA considered, which uses the determination of Avoided Costs is the most promising, and is far superior to the first two Alternative approaches which are seriously flawed. (1) The Definition of the “Renewable Energy Development Rate” is Not Suitable to Determine State RE Targets. The EPA’s definition of the RE development rate used in the Alternative Approach as the amount of existing RE generated in a state divided by its technical potential211 is not a suitable metric with which to determine State RE targets. As a simple proportion of the state’s 2012 realized technical potential, it is not an informative measure of what should be a plausible or economically justifiable level of RE deployment in other states. To assume the same proportion of realized technical potential in the “top” states can also be realized in “lagging” states requires that one assumes other states are similar to the top states in terms of renewables endowment, existing regulations, electricity prices, local incentives and all the other factors that have allowed top states to achieve their levels of RE generation. It should be clear to the most casual observers that the differences in these factors between states is very large; therefore, it is not rational to assume similar proportions of realizable technical potential are practical. For the above reasons, Duke Energy does not support setting targets based on the proportion of technical potential which some states have been able to realize. However, if the EPA insists on this type of approach, it can be improved by looking at the amount of RE generated in a state divided by the state’s RE Economic Potential212 – or the amount of RE 211 TSD – Alternative RE Approach Technical Support Document, Sect. 1.2. See: IPCC’s Fourth Assessment Report http://www.ipcc.ch/publications_and_data/ar4/wg3/en/ch2s2-4-3-1.html “…‘economic potential’ is defined as the potential for cost-effective GHG mitigation when non-market social costs 212 111 already deployed divided by the amount that IPM model runs indicate would deploy at a defined CO2 price. This new factor could then be applied to the RE Economic Potential for defined regions in which the RE endowment is most similar. (2) Regarding the Proposed Solution to the Limitation of Using a State’s Technical Potential to Set Targets in the Alternative RE Approach Technical Support Document. The EPA acknowledges the limitations of using technical potential to establish state RE targets, but proposes a solution that seems to arbitrarily reduce the cost of RE input assumptions used in the energy model (IPM) by $30/MWh to produce a result of how much RE is “economically” deployed. This is “intended to represent the avoided costs of other actions that could be taken instead to reduce CO2 emissions from the power sector.”213 This is a misapplication of avoided cost. The avoided cost will vary by region. A single number applied across the country is a misapplication of the concept of avoided cost. See Section VII.A.2.(h)(4) below for a description of the proper way to determine the avoided costs for a state or region. If the EPA must pursue this approach [noting our earlier suggestion for how to use existing state RPS targets given in previous sections)], it should consider instead using the IPM model with an imposed CO2 constraint, then let the model meet the constraint at the lowest cost without changing the cost assumptions for RE technologies used in the model. The model output would presumably include some amount of RE for the region, which could then be apportioned between the states based on an examination of each state’s relative endowment of economic RE resources. If this is unacceptable, the EPA could apply a CO2 price slightly less and benefits are included with market costs and benefits in assessing the options[17] for particular levels of carbon prices in US$/tCO2 and US$/tC-eq. (as affected by mitigation policies) and when using social discount rates instead of private ones. This includes externalities (i.e. non-market costs and benefits such as environmental co-benefits). Note that estimates of economic potential do not normally assume that the underlying structure of consumer preferences has changed.” 213 TSD – Alternative RE Approach Technical Support Document, Sect. 1.2. 112 than the Social Costs of Carbon214 of $13/ton in 2020, increasing to $17 by 2030215 to ensure cost do not exceed benefits and then use the IPM output to set the RE building block target. (3) Large Differences in State RE Targets Between the Two Approaches Should Cause Some Concern Regarding the Validity of Either Approach. The extremely large difference in state RE targets from the two alternative approaches (by a factor of 10 in the wind section alone) indicates that the two targets have no common analytical basis upon which they are justified. This should be the final indicator that either or both approaches are fundamentally flawed and may be indefensible. Rather than use either of these methods, Duke Energy recommends that the EPA use the avoided cost methodology described in the next section. (4) Using Avoided Cost Calculations Is the Better Way to Determine State RE Targets. The approach described in the section “Potential Alternative Method Using Technical and Economic Potential”216 of the TSD (20140602tsd-alternative-re-approach), with the suggested improvements given below, is the most analytically sound of the many approaches being considered by the EPA. It is worth noting that the approach described in this section of the TSD is similar to that used by the industry to evaluate the cost-effectiveness and potential of energy efficiency programs. To correctly perform an avoided cost analysis, the EPA should:  Run models at the state or regional level similar to the models used by utilities performing the Integrated Resource Planning (“IRP”) modeling, including RE options (including capital, 214 Being mindful of our earlier stated concerns with the SCC as expressed by EPRI in: http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?productId=000000003002004657. 215 2020 & 2030 SCC at 5% discount rate. http://www.epa.gov/climatechange/EPAactivities/economics/scc.html. 216 20140602tsd-alternative-re-approach, pg. 7. 113 operating costs, operating characteristics and a CO2 price less than the Social Cost of Carbon at a 5 percent discount rate). o If the model then selects RE sources: 1. Take the generation plan from the IRP modeling and insert it into a production cost model (such as ProMod or Aurora) to project the production cost by year. 1. Remove the RE component from the input of the production cost model and run the model again, requiring it to meet electricity load with other existing sources that include carbon costs (assigned price noted above) and other production costs. 2. Take the difference in production costs between a) and b) above to determine the avoided energy costs/MWh for RE. o If the model selected RE, then the avoided cost from employing RE is equal to the [capital cost from a generation plan without RE] minus the (capital cost of the generation plan with RE). That is: Avoided Cost=[capital cost from a generation plan without RE] – [capital cost of the generation plan with RE]. Total avoided costs are the sum of the two components. o In cases where the modeling does not pick RE, then RE should be forced into the model outputs (2 percent of the technical potential as example). 1. Take the generation plan from the model including the forced RE output and then use in a production cost model (such as ProMod or Aurora) to project the production cost by year. 2. Remove the RE component from the input of the production cost model and run the model again, requiring it to meet electricity load with other existing 114 sources, including the carbon costs (assigned price) and other production costs. 3. Take the difference in production costs between a) and b) above to determine the avoided energy costs/MWh for RE. o This time the avoided cost of the RE is (generation plan with RE) minus (generation plan without RE). This will be a negative number, meaning RE is not competitive with conventional generation even after inclusion of the CO2 price. In that case, the state should have no RE building block as RE is not an economic choice to lower CO2. B. Issues Related to the EPA’s Proposed Treatment of Existing, Under Construction, and New Nuclear. 1. The EPA’s Proposed Treatment of Existing Nuclear Capacity is Inappropriate and Must Be Changed. The EPA has proposed that 5.8 percent of each state’s 2012 nuclear capacity be factored into the state goals for the respective states. The EPA indicates that for purposes of goal computation, generation from existing nuclear capacity is based on an estimated 90 percent average utilization rate for U.S. nuclear units.217 The EPA invites comment on all aspects of its proposed approach for treating existing nuclear capacity, and specifically requests comment on whether it should include in the state goals an estimated amount of additional nuclear capacity whose construction is sufficiently likely to merit evaluation for potential inclusion in the goalsetting computation. In the first instance, as stated previously in these comments, a standard of performance for fossil fuel-fired EGUs cannot be based on actions taken beyond the source itself. This would 217 79 Fed. Reg. at 34,871. 115 include the consideration of any amount of nuclear generation as BSER. While nuclear power is the single greatest CO2 mitigation option available in the power sector, that fact does not authorize the EPA to use it in the setting of CO2 emission standards for fossil fuel-fired EGUs. With respect to setting emission standards for fossil fuel-fired EGUs, it is irrelevant whether a state has or does not have nuclear capacity; it has nothing to do with controlling emissions from existing EGUs, nor should it. There is no basis under the CAA for setting different emission standards for identical EGUs that just happen to be in two different states, one with nuclear capacity and the other without. In the second instance, putting aside the fact that the inclusion of generation from existing nuclear units as a component of BSER for fossil fuel-fired EGUs is not authorized by the CAA, the EPA’s proposal to include 5.8 percent of existing nuclear capacity as BSER and reflect the associated amount of MWh generation in state goal calculations is without merit. The EPA must not finalize any guidelines for fossil fuel-fired EGUs that includes any amount of existing nuclear generation in its BSER determination and calculation of state goals. The notion that 5.8 percent of any existing nuclear plant is at risk of premature retirement is irrational. The EIA’s Annual Energy Outlook cited in the EPA proposal218 which projected an additional 5.7 GW of unspecified nuclear capacity reductions to the nuclear fleet is not evidence that any amount of any existing nuclear unit is at risk of premature shutdown and therefore neither supports nor authorizes the EPA’s proposal in this regard. Even if one were to assume for sake of argument that the EIA projection is reasonable, it is certainly not reasonable for the EPA to then take that information and assume that 5.8 percent of every existing nuclear unit in the country is at risk of premature retirement. 218 79 Fed. Reg. at 34,871. 116 It is generally understood that those existing nuclear generating units potentially at risk of premature retirement are concentrated in a relatively small number of states where the units operate in competitive electricity markets and are exposed to low wholesale electricity prices. The majority of existing nuclear capacity is not exposed to those economic pressures and are not at risk of premature shutdown. To be correct, the 5.8 percent factor should be higher in states with units “at risk” and zero elsewhere. It appears the EPA simply took the 5.8 percent value as a convenient way to provide some incentive for continued operation of nuclear power plants; ironically, most plants are not in need of such an incentive and the ones that are potentially “at risk” are not helped by the arbitrary 5.8 percent factor. The EPA’s GHG Abatement Measures Technical Support Document219 states that “[I]ncreasing the amount of nuclear capacity relative to the amount that would otherwise be available to operate is a technically viable and economically efficient approach for reducing CO2 emissions from affected fossil fuel-fired EGUs.” This statement suggests that the EPA’s proposed treatment of existing nuclear capacity would in fact avoid the premature retirement of existing nuclear capacity. There is, however, no basis for such an assertion. In the first place, the EPA has not identified any existing nuclear unit that it believes is at risk of premature shutdown. In the second place, the EPA can provide no evidence that its proposal, if implemented, would avoid the premature shutdown of a single MW of existing nuclear capacity in the country. But even if the EPA were able to make such a demonstration, it would still not be authorized to include existing nuclear in its BSER determination for fossil fuel-fired EGUs or factor any amount of existing nuclear capacity into the state goal calculation. Section 111(d) of the CAA applies to existing fossil fuel-fired EGUs. 219 EPA-HQ-OAR-2013-0602-Later 117 Duke Energy owns and operates the largest fleet of regulated nuclear units in the country. Our 11 operating units are located in North Carolina and South Carolina and are the first units to dispatch because they are our lowest cost base load generation. These units are not currently at risk of premature retirement220 and it is inappropriate for the EPA to include any portion of this nuclear capacity in the goal setting for North Carolina or South Carolina. The only thing the EPA proposal achieves is to make the goals for North Carolina and South Carolina, and every other state with existing nuclear, more stringent than they otherwise would be, and introduce in those states an additional compliance risk if an existing nuclear unit or units are not able to operate at the assumed 90 percent annual capacity factor. There is also the issue of whether any existing nuclear units will be granted a license extension beyond the expiration of their current licenses.221 Nuclear power reactor license extension beyond sixty years has not been done in the United States, so there is uncertainty associated with the technical and economic feasibility of doing so. With the EPA proposal, if an existing nuclear unit’s current license is not extended for whatever reason, the practical effect would be to make a state’s goals more stringent because the state would lose a significant amount of non-CO2 emitting generation that was factored into its goal computation.222 If a license were not extended, the lost generation would have to be replaced with an equal amount of new nonemitting generation, and/or other steps would have to be taken to offset the loss of the nuclear generation. A similar situation would arise if an event occurred at an existing nuclear unit that 220 Premature retirement being defined as retiring before the expiration of a unit’s current operating license, which for each of Duke Energy’s nuclear units is 60 years from the date of initial operation. 221 Sixty years in the case of Duke Energy’s 11 nuclear units. 222 The final decision regarding the possible extension of an existing nuclear unit’s license would rest with the Nuclear Regulatory Commission. Even if the owner of an existing units applies for an extension, it cannot be assumes today that it would be granted. States have no authority regarding whether an existing nuclear unit continues to operate or not, and they should not be penalized for something that is totally outside their ability to control. 118 could not be overcome and the unit was forced to shut down. The additional cost to consumers in states that would need to comply with essentially a more stringent goal could be significant. Factoring any amount of existing nuclear generation in a state’s goal computations inappropriately builds compliance risk into the program when the units eventually shut down. Under the EPA’s Proposed Guidelines (absent the contribution of “nuclear at risk” in Building Block 3), there is already an incentive for states to keep nuclear power plants operating. Absent the adjustment for nuclear at risk, the actual effect of a nuclear plant closure would be an increase in the numerator of the greenhouse gas emissions rate equation, if it resulted in more generation from affected coal and/or NGCC units to make up for the missing nuclear generation, resulting in a higher emissions rate. Therefore, there is no need to include the arbitrary 5.8 percent factor to the calculation to make shutting down nuclear more undesirable from a CO2 emissions perspective because it already is undesirable. If the EPA finalizes its proposal and continues to include existing nuclear units in state goal computations, it must include safety valves that would allow for a state’s goal to be recalculated without the existing unit if the unit continued to operate through the end of its current license period but its license was not extended for whatever reason, in the event of premature shutdown due to equipment failure and/or damage to the plant where repair cost is not justified, or where the cost of maintaining the plant in compliance with regulation is not economic given the unit’s remaining useful life. With respect to the assumption of a 90 percent capacity factor for nuclear power plants going forward, it is challenging but generally consistent with recent performance of nuclear power plants in the United States as a whole. However, there is no guarantee of maintaining that performance in the future with an aging fleet of plants. Obviously a major equipment failure or 119 regulatory shutdown at one or more units can adversely and significantly impact capacity factor. Any final guidelines that include existing nuclear in state goal calculations at a 90 percent capacity factor should make allowances in compliance in the event of unanticipated losses of nuclear generation. For example, states should not be penalized for a nuclear unit’s failure to operate at 90 percent capacity factor unless the plant was intentionally shut down or operated at less than full power when more power could actually have been generated from the unit. 2. Existing Nuclear Units That are Relicensed Beyond 60 Years Should be Treated as New Capacity There is no indication that the EPA considered the fact that existing nuclear units can operate only for the period of their licenses. In other words, the EPA seems to have incorrectly assumed that existing nuclear units will operate indefinitely. This is of course incorrect. There is currently no existing nuclear unit that is licensed to operate longer than 60 years. The process and requirements for units to receive an extension beyond 60 years is still under development. The NRC has begun a regulatory framework and technical justification review of the operating power reactor license renewal process to be prepared for anticipated subsequent license renewal applications that will request approval to renew a facility’s operating license, but it has not yet decided on the terms under which it may grant second license renewal applications. Even if the NRC does grant additional license renewals beyond 60 years, the EPA has no valid basis to assume that every plant currently operating will continue to receive repeated license renewals into the indefinite future, as its current approach implicitly does. Extending the operating license of a nuclear units will require a significant investment on the part of the plant owner/operator. If the EPA is serious about incentivizing the continued operation of existing nuclear units, it should start by assuming that no existing nuclear unit will operate beyond 60 years. It should also consider any unit that is relicensed to be a new unit that 120 that allows states to include all the generation from the relicensed unit in compliance demonstrations. While adopting this approach will not guarantee that existing nuclear units can or will be able to continue operation beyond 60 years, it would provide a significant economic incentive to do so. 3. The EPA Should Not Include Under Construction Nuclear Units in State Goal Computations. The EPA has proposed that the projected generation provided by five nuclear units currently under construction223 be factored into the state goals for the respective states where the under construction units are located. The EPA is making this proposal because of its belief “…that since the decisions to construct these units were made prior to this proposal, it is reasonable to view the incremental cost associated with the CO2 emission reductions available from completion of these units as zero for purposes of setting states’ CO2 reduction goals.”224 Duke Energy opposes the EPA’s proposal to incorporate the projected generation from under construction nuclear units in state goal computations. In addition to exceeding the EPA’s authority under section 111(d) of the CAA to include under construction nuclear in its BSER determination for fossil fuel-fired EGUs, the only thing the proposal achieves is to make the goals for South Carolina, Georgia, and Tennessee significantly more stringent. Penalizing these states for supporting the continued development and deployment of nuclear power, the single largest CO2 reduction option available within the power sector, in a rule intended to reduce CO2 emissions within the power sector, is misguided from a policy perspective. Including generation from the under construction nuclear units in the state goal computations also introduces a 223 These include two units at the Summer plant in South Carolina, two units at the Vogtle plant in Georgia, and one unit at the Watts Bar plant in Tennessee. The EPA has calculated the amount of generation from these five units based on each operating at a 90% capacity factor. 224 79 Fed. Reg. at 34,870. 121 significant risk of noncompliance if the units are either not completed, or are completed but do not perform as the 90 percent capacity factor the EPA has assumed. If the EPA proceeds with finalizing its Proposed Guidelines, it should do so without including in the goal computations for South Carolina, Georgia, and Tennessee any contribution from the under construction nuclear units. The EPA should also make it clear that if the units are completed, their output should be available to the states for compliance. 4. Duke Energy Supports the EPA’s Proposed Treatment of New Nuclear Generating Units and Uprating of Existing Nuclear Units. The EPA has proposed that any additional new nuclear generating units or uprating of existing nuclear units, relative to a baseline of capacity as of the date of proposal of the emission guidelines, could be a component of state plans. The EPA requests comment on alternative nuclear capacity baselines, including whether the date for recognizing additional non-BSER nuclear capacity should be the end of the base year used in the BSER analysis of potential nuclear capacity (i.e., 2012).225 In addition, the EPA requests comment on whether to include in the state goals an estimated amount of additional nuclear capacity whose construction is sufficiently likely to merit evaluation for potential inclusion in the goal-setting computation.226 Duke Energy supports the EPA proposal to allow both new nuclear generating units and uprating of existing nuclear generating units to be factored into state compliance. With regard to the baseline issue, Duke Energy recommends an end of base year be used for the purpose of recognizing additional nuclear capacity227 and uprating of existing nuclear units. 225 79 Fed. Reg. at 34,923. Id. at 34,871. 227 Additional new nuclear capacity and under construction nuclear capacity are not the same. 226 122 Duke Energy opposes any attempt by the EPA to include in the state goals any amount of additional nuclear capacity. Putting aside the fact that the EPA is not authorized by the CAA to use any nuclear generation in its BSER determination for fossil fuel-fired EGUs, Duke Energy does not believe it is remotely possible today to make any determination regarding what additional nuclear capacity might be brought on line in the future. Applying for the necessary permits and operating license for a new nuclear unit, for example, does not guarantee that the unit or units will actually be built. The typical approach today is for a company to first obtain a combined construction and operating license and only then make an investment decision on whether to proceed with construction. The issuance of all the necessary permits and license does not guarantee the nuclear unit or units will be built. Furthermore, history can attest that even the commencement of construction does not guarantee that a unit or units will be completed. The bottom line is there is no new nuclear unit whose construction and future operation is a certainty, and the EPA should not attempt to include any future nuclear units in state goal computations. Doing so inappropriately penalizes states where new nuclear is being considered, an odd policy position in a rule designed to reduce CO2 emissions. If the EPA were to include future nuclear units in a state’s goal computation and the unit or units were not built, it would cripple the state’s ability to meet its goal. 5. The EPA Should Recognize that Generation From New Nuclear Power Plants Will Cross State Boundaries and Should Allow the Importing State to Factor the Generation into its Compliance Demonstration. The EPA clearly understands that electricity generation from renewable resources crosses state boundaries. In fact, the EPA has proposed that states can use renewable energy generated from outside their boundaries in their compliance demonstrations under a rate-based program. The EPA is not proposing to allow equal treatment for nuclear generation, but it must. 123 Duke Energy operates in and serves customers in, among other states, North Carolina and South Carolina. Duke Energy has applied for a combined operating license for the Lee Nuclear Station, which if built, will be located in South Carolina. The fact that it would be built in South Carolina, however, does not mean that it will exclusively serve our South Carolina customers. The electricity that would be produced from the Lee Nuclear Station would serve our customers in both states. In addition, our North Carolina customers would pay the largest share of the cost of the facility. And while the generation that comes to North Carolina from the Lee Nuclear Station would help lower the CO2 emissions of our North Carolina operations, under the Proposed Guidelines, North Carolina would be prohibited from considering any of the generation from the Lee Nuclear Station in its compliance determination unless North Carolina and South Carolina develop a joint plan. This does not make sense. Therefore, Duke Energy believes that the EPA should allow a state such as North Carolina that is importing electricity from a new nuclear unit in another state to be able to factor that generation into its compliance demonstration, as long as it is not being double counted by the state hosting the nuclear facility. This would simply treat generation from new nuclear units the same way the EPA is proposing to treat generation from renewable resources. VIII. Building Block 4 A. Customer Behavior Impacts Adoption of Demand-Side Energy Efficiency Programs. Duke Energy agrees that demand-side energy efficiency programs have the potential to reduce CO2 emissions as well as help to minimize the long-run cost of supplying electricity. However, utility driven installation of energy efficiency measures requires customer participation for this to occur. Customer adoption of measures in utility energy efficiency programs is voluntary. Utilities are limited to offering the programs, promoting the programs 124 and providing incentives. The ultimate decision of whether to adopt an energy efficiency measure rests entirely with the customer. Illustrating this point are the following two examples:  CFL Light Bulb Program Since 2009, Duke Energy has been offering free or highly discounted CFL bulbs to residential customers and have provided customers with nearly 39 million compact florescent lights. This program has reached over 63 percent of our active residential customer accounts. Of that 63 percent, over 56 percent have received 15 CFLs, the maximum number of bulbs a single residential account can receive. Over 90 percent of these bulbs have been mailed directly to the customer’s home eliminating the need for customers to take any significant action -such as taking a coupon to a store. This extremely successful program is designed to eliminate barriers to participation and make it as easy a process as possible by allowing customers to simply enroll on the company’s website, respond to a mailed offer, or place an order over the phone. Even though it is free and easy, over one third of customers have not participated in the program.  Residential Appliance Recycling Program In 2012, Duke Energy launched residential appliance recycle programs in several states. Duke Energy offers to pick up old appliances at the customer’s home and pay them a cash incentive. Initial program research indicated that customers are mostly motivated by the free inhome pick-up and potential energy savings from removing the inefficient appliance. Even with a robust marketing plan that included bill inserts, direct mail, electronic offers and mass media TV/radio spots, the program struggled to meet even 50 percent of the targeted participation. Customers did not respond to an offer that provided simple enrollment, free home pick up, $100 annual electric bill savings and a paid cash incentive. A pricing study was then conducted to better understand the elasticity of program enrollment when the incentives were increased. The new research indicated that the cash incentive was more important than previously thought, so by changing the incentive from $30 to $50 per appliance the program participation improved by more than 200 percent but overall saturation is still low. Since launching in 2012, just over 40,000 appliances have been recycled through this program. Voluntary customer participation is only one of the reasons why it is not appropriate for the EPA to have proposed that demand-side energy efficiency be a component of its proposed BSER for coal-fired EGUs. Its adoption is beyond the control of the regulated source. Even if it were lawful, it is simply not appropriate for the EPA to establish CO2 emission limits for coalfired EGUs that are based in part on something which the plants have no control over. In its Proposed Guidelines, the EPA has failed to take into account that customer behavior is beyond the control of public utilities or states. Instead, customer adoption of energy 125 efficiency programs depends on a number of factors including, but not limited to, the cost of electricity, the maturity of the programs, the incremental cost of the technology to the customer, the availability of more energy efficient equipment, the climate, the customer mix, and the socioeconomic demographics within a jurisdiction. These factors vary significantly from one state to another, and can even vary across utility service area within a state. Grand macro assumptions applied across all states and service areas do not properly reflect the efforts to obtain the maximum benefits of energy efficiency at the least cost, and they invariably result in assumptions that are incorrect and inapplicable for some areas. Nevertheless, the EPA’s Proposed Guidelines would require that these macro assumptions be applied in every state. 1. The Price of Electricity Is An Important Factor Affecting Adoption of Energy Efficiency Measures. Probably the most important factor affecting adoption of demand-side energy efficiency measures is the price of electricity. The higher the price of electricity, the more customers will likely find that the installation of energy efficient measures is cost-effective for their circumstances. This is analogous to the measure of price elasticity often found in utility econometric-based load forecasting models. As the price of electricity (in real dollars) rises over time, usage per customer is projected to decline. Customers can achieve these price-driven energy use reductions, in part, by installing more energy efficient equipment. Rising prices reduce the payback period and make the measures more economically attractive. In states where electricity prices have remained relatively low, customer adoption of energy efficiency programs, measured as a percentage of retail electricity sales, historically has been lower than in states where electricity prices are much higher. In its Proposed Guidelines, the EPA refers to data reported by utilities to the EIA showing that in 2012, the five states (California, Connecticut, Minnesota, Rhode Island, and Vermont) with the highest cumulative energy 126 efficiency savings had achieved, on average, a cumulative reduction in load of 13.4 percent. 228 The EPA refers to this data as evidence of what can be achieved and implies that all states can achieve this level of load reduction. A closer look at the data from the EIA Form 861 shows that the average retail electricity prices for those same five states in 2012 was 12.98 cents per kWh.229 This is over 50 percent higher than the average for 34 states, or two-thirds of the 50 states plus the District of Columbia. The EIA data strongly suggest that higher electricity prices are linked to a higher rate of customer installation of energy efficiency measures. Also, it is important to note that in 2012, these same five states achieved incremental savings as a percentage of retail sales of 1.28 percent on average, 230 not the 1.5 annual percentage increase the EPA has proposed as the basis for setting state energy efficiency targets for its preferred Building Block 4 approach. This calls into question the technical basis for EPA’s proposed 1.5 percent annual incremental savings rate target because the EPA has not demonstrated that the leading states can sustain the targeted level of projected energy efficiency savings. To achieve the annual 1.5 percent incremental savings rate the EPA has proposed, customers in all sectors (residential, commercial, and industrial) must be willing to aggressively adopt programs offered by the utility. Customer behavior is difficult to predict, but when the cost of energy increases, customers have a larger incentive to reduce energy consumption to save money. The EPA has focused primarily on energy efficiency policies and programs that increase the energy efficiency of buildings, appliances, and industrial operations and has paid little or no 228 Energy Information Administration Form 861 for 2012, www.eia.gov/electricity/data/eia861. While the average retail price in Minnesota (one of the five states) is near the average for the nation, it does not refute the fact that higher electric prices make it easier for customers to cost-justify investments in energy efficiency, which makes implementation of energy efficiency programs easier in states with higher retail prices. Also, it is important to note that Minnesota’s achievement includes codes and standards. 230 See Table 5-4 on pages 5-17 to 5-19 of the USEPA’s GHG Abatement Measures TSD, Docket ID No. EPA-HQOAR-2013-0602. 229 127 attention to customer behavior, which will ultimately determine the level of efficiency gains that can be achieved. 2. The EPA Has Not Accounted for the Fact That Demand-Side Energy Efficiency Programs Are Maturing. The demand-side energy efficiency industry is maturing. Many customers have already taken advantage of energy-efficient lighting, appliance recycling, and other long-standing programs to deliver greater energy efficiency. The lower-cost and easy-to-adopt programs have been the most widely adopted programs, which is why some states have historically experienced high percentages of avoided energy demand savings. According to data provided on the California Public Utility Commission’s Energy Efficiency Data Portal, energy efficiency savings in California were achieved mostly by indoor lighting in the commercial and residential sectors.231 The rate of energy savings due to indoor lighting has reached a point of saturation that cannot be sustained without a new technology that can create light more efficiently than lightemitting diode (“LED”) technology. While LED technology creates efficiency savings compared to compact fluorescent (“CFL”) technology, the incremental energy savings when going from CFL to LED lighting are significantly smaller than the historical savings generated from moving from incandescent lights to CFLs. For example, the electricity usage of a 60 watt incandescent bulb became 13 watts (a 78 percent incremental reduction) with the move from incandescent to CFL; but, the move from a 13 watt CFL to a 10 watt LED (which costs significantly more than an equivalent CFL) results in only 3 watts of savings (only a 23 percent incremental reduction). While there is a savings opportunity when moving from CFL to LED 231 http://eestats.cpuc.ca.gov/Views/EEDataPortal.aspx. 128 lighting, the incremental savings will be relatively small, and certainly will not support the rate of year-to-year energy efficiency savings that have been achieved historically. To illustrate further, assume that a residential customer uses 12,500 kWh per year (average usage for Duke Energy residential customers) and the customer converts 15 bulbs from incandescent to CFL. Based on an annual savings of roughly 43 kWh/year per bulb (60 watts to 13 watts, 2.5 hours per day), the customer realizes a total savings of approximately 643 kWh/year or roughly 5 percent of the total annual electricity usage. By 2017, it is expected that the overwhelming majority of residential households will have already achieved these savings. The move from CFL to LED would result in only an additional 3 kwh/year per bulb (13-10 watts, 2.5 hours per day) for a total annual savings of only an incremental 41 kWh/year, which is roughly 0.3 percent of the customer’s annual electricity usage, net of the CFL savings already achieved. This illustration shows that the move from CFLs, a technology that is already widely adopted, to the next rung on the lighting efficiency technology ladder, LEDs, will result in only a marginal incremental increase in energy savings. This same technology development and adoption trend applies to many other end-use technologies, including heating, ventilation and air conditioning (“HVAC”) equipment which represents a major driver for the higher energy use of residential customers in Duke Energy’s service territories. Despite the maturity of energy efficiency programs such as lighting, Duke Energy has found that some customers are still unwilling to adopt even these relatively low-cost energy efficiency measures. Unlike lighting, HVAC and large appliances represent durable goods that represent a significant cost for most consumers. When deciding whether to purchase a unit of electricity or to invest in energy efficiency, many customers will respond by purchasing the unit 129 of electricity and spending their dollars on other goods and services that they perceive have a higher value for them. 3. The Potential Lack of Availability and the Cost of More EnergyEfficient Equipment Impacts Customer Adoption. In its Proposed Guidelines, the EPA did not assume any particular type of demand-side energy efficiency policy, but the EPA did note that appliance standards is a policy that has been used at the federal and state levels to accelerate the deployment of demand-side energy efficiency technologies.232 What the EPA did not appear to take into account is that it may take years for more energy-efficient appliances such as refrigerators, air conditioners, washing machines, and clothes dryers to come to the market and even longer for customers to embrace them. The EPA’s Proposed Guidelines ignore the length of time it takes for more energyefficient equipment to enter the market, and compounds that mistake by ignoring consumer preference and assuming that consumers will readily purchase these types of appliances, particularly in situations where the purchase of a more efficient appliance would occur prior to the end of the useful life of the existing appliance. Customers do not go out and immediately purchase a new washer and dryer simply because a more energy efficient one has become available. Additionally, as has been the case with new efficiency technologies that have already entered the market, the incremental savings that can be achieved through technological advancement declines over time relative to earlier advancements. As discussed above, moving from CFLs to LEDs provides little relative improvement in efficacy when compared to moving from incandescent bulbs to CFLs. Similarly, early heat pump technology was relatively inefficient compared to today’s standards, but the 1980’s vintage heat pumps have been largely 232 79 Fed. Reg. at 34,872 130 replaced with drastically more efficient heat pumps. As a result, replacement of today’s more efficient heat pumps will likely result in only a modest improvement in efficiency. 4. Regional Climate Impacts the Adoption of Energy Efficiency Programs. The climate in a given jurisdiction has a significant impact on the development of and the adoption of energy efficiency programs and the energy savings that can be achieved with certain programs. In its Proposed Guidelines, however, the EPA does not take into account that climate impacts customer behavior, thus affecting the ability of a jurisdiction to meet the Agency’s proposed energy efficiency goals. In regions where summers are typically hot, consumers will generally use their air conditioners and/or heat pumps regardless of the efficiency of their equipment. To be comfortable, consumers may choose not to adjust their thermostat or allow the utility to adjust their usage even if financial incentives are offered. In jurisdictions with hot and/or humid climates where air conditioners consume a significant portion of the utility’s load, it is difficult to develop cost-effective energy efficiency programs that provide enough of an incentive for customers to adopt demand-side energy efficiency programs because of the large customer outof-pocket cost required to purchase the more efficient equipment. As a result, once the savings from indoor lighting have been achieved, additional energy efficiency savings are difficult to achieve in climates where HVAC equipment is a major driver of the customer’s usage. 5. Customer Mix Impacts the Savings Each State Is Able to Achieve Through Demand-Side Energy Efficiency Measures. Each state has a different customer mix (i.e., residential, commercial, industrial, and agricultural). The EPA’s Proposed Guidelines do not take into account customer segmentation and how this impacts each state’s energy efficiency savings potential. For example, Duke Energy’s service territories include a large number of industrial customers. In most of Duke 131 Energy’s jurisdictions, state regulations allow certain larger energy using industrial and commercial customers to elect not to participate in public utility-offered energy efficiency programs (commonly referred to as “opt-out”) and hence be relieved of the obligation for paying the costs of the utilities’ demand-side energy efficiency programs. For industrial customers electing to opt-out, utilities are not involved in either offering or measuring the impact of demand-side energy efficiency programs, if any, they may adopt. The EPA’s Proposed Guidelines do not clearly state how demand-side energy efficiency will be addressed where entire classes of customers are eligible to opt-out. However, any EPA rule that requires electricity savings from end-use energy efficiency measures must make it clear that the targeted energy savings only apply to sales net of the loads that have opted-out of the program. In addition, since utilities are not required to verify, measure, or report the energy efficiency impacts associated with opt-out customers as part of their energy efficiency achievements, it is unclear how any energy efficiency savings associated with opt-out customers would be tracked for the purpose of the EPA’s rule. Establishing a requirement for the utility to verify, measure, and report the impacts associated with opt-out customers is contrary to state statutes, in some cases, and at a minimum, would require the establishment of a mechanism to allow a utility to recover the costs for tracking these energy savings from the industrial and commercial sectors. However, the energy use reductions achieved as a result of these opt out customers’ demand-side energy efficiency programs need to be factored into the calculation of the overall state goals, as these savings may be a significant contributor to the CO2 reduction achieved through energy efficiency. Therefore, the EPA needs to determine how, and by whom, these savings should be reported. 132 6. Socioeconomic Demographics Impacts Customer Behavior. In its Proposed Guidelines, the EPA failed to recognize that each state has a different socioeconomic demographic which impacts customer behavior. Buying new appliances, retrofitting a home with energy efficient features, and/or buying a new home that meets new building standards may not be affordable depending on the socioeconomic mix of customers in the state. The greatest opportunity for electricity savings, for example, often comes from older manufactured homes which are typically occupied by lower income individuals or families that are unlikely to be able to afford costly energy efficiency investments. Consequently, certain households are less likely to invest in costly energy efficiency measures or programs. B. Annual Incremental Energy Savings Targets. The EPA proposes a 1.5 percent annual incremental savings rate (net) and considers this rate to be a reasonable estimate of energy efficiency performance that is either already being achieved or is required by leading states and that can therefore be achieved at reasonable cost by all states given adequate time.233 In its Proposed Guidelines, the EPA invited comments on a less stringent requirement of 1.0 percent annual incremental savings. Also, the EPA invited comments on the data it used to derive the annual incremental savings targets and specifically on several issues including: “(1) Increasing the annual incremental savings rate to 2.0 percent and the pace of improvement to 0.25 percent per year to reflect an estimate of the additional electricity savings achievable from state policies not reflected in the 1.5 percent rate and the 0.20 percent per year pace of improvement, such as building energy codes and state appliance standards, (2) alternative approaches and/or data sources (i.e., other than EIA Form 861) for determining each state's current level of annual incremental electricity savings, and (3) 233 79 Fed. Reg. at 34,872. 133 alternative approaches and/or data sources for evaluating costs associated with implementation of state demand-side energy efficiency policies.”234 1. Annual Incremental Savings Targets of 1.5 Percent And 1.0 Percent Are Not Sustainable. The EPA used a mix of historical data and future goals on energy efficiency program savings for twelve states235 to conclude that annual incremental savings rates of at least 1.5 percent of the electricity demand is achievable in all states, despite the fact that only three of the 50 states plus the District of Columbia achieved the 1.5 percent threshold in 2012.236 Furthermore, the EPA has ignored the fact that for nine of the twelve states cited, the 1.5 percent or greater savings targets do not take effect until the year 2020. This raises a question as to whether the EPA should be setting goals based on assumptions that these states will actually achieve these targeted goals in the future. Establishing a goal based on what a state might achieve in the future is speculative, as the state established targets could be changed, removed or simply not achieved. This has already happened in Indiana,237 one of the twelve states cited by the EPA, where the General Assembly in 2014 eliminated the previously Commission enacted state energy efficiency mandates due to concerns about the feasibility and cost of achieving them. Duke Energy believes the EPA’s overly simplistic and rather narrow analysis fails to demonstrate the applicability or the feasibility of an annual incremental savings rate of at least 1.5 percent across the broader 50 states. The EPA failed to analyze the life-cycle of the historical programs in the twelve states used by the EPA as the basis for its proposed annual 234 Id. at 34,875. The twelve states include ME, AZ, CO, IL, IN, MA, MN, NY, ON, RI, VT, and WA. 236 GHG Abatement Measures Technical Support Document, Docket ID No. EPA-HQ-OAR-2013-0602, June 10, 2014 at 5-33. 237 Senate Enrolled Act 340. 235 134 energy savings rate target, and the other factors discussed in Section VIII.A of these comments. A deeper analysis of the twelve states the EPA cites shows that indoor lighting (i.e., retrofitting to CFL technology) has driven historical savings far more than any other program or measure including, but not limited to, building energy codes, state appliance standards, tax credits, and benchmarking requirements for building energy use. As indoor lighting continues to mature and energy efficiency standards increase for buildings and appliances, these programs will not yield future impacts on par with the historical impacts. Therefore, other more costly and perhaps less effective programs will have be implemented to meet the EPA’s proposed targets. In order for a utility to invest in other demand-side energy efficiency programs to meet the targets, the measures and/or programs will need to be cost-effective to meet state utility commission requirements. Given the absence of a uniform system-wide carbon price to determine the costeffectiveness of a program or measure, utilities may be precluded from offering necessary programs to meet the level of demand-side energy efficiency the EPA assumes in the Proposed Guidelines. Plus, as stated previously, the ultimate decision of whether to adopt an energy efficiency measure rests entirely with the customer. a) The Price of Electricity Must be Factored Into the EPA’s Analysis. In its Proposed Guidelines, the EPA’s analysis focused on the twelve states that have historically achieved or have established state energy efficiency requirements that may lead them to achieve at least 1.5 percent annual incremental savings. However, the EPA did not analyze the price of electricity for those states that have actually achieved the highest cumulative energy savings. An examination of the 2012 EIA data in Form 861 shows the residential use per customer for the five leading states previously identified to have achieved the highest cumulative energy efficiency impacts was on average 7,901 kWh. At the same time, the usage per 135 residential customer for states in which Duke Energy provides electricity238 averaged 12,596 kWh, or 59 percent higher. The residential prices in those same five states averaged 38 percent higher than in the states in which Duke Energy serves customers. The combination of higher electricity usage and lower rates raises the energy efficiency bar for Duke Energy to meet. For the five states, a 1.5 percent annual savings would have been roughly 118 kWh per customer in 2012 versus 189 kWh per Duke Energy customer. The Duke Energy states will have to achieve 59 percent more energy efficiency installations than these five states to reach the same percentage reductions for the residential class customers (see the table below). 238 They include North Carolina, South Carolina, Florida, Kentucky, Indiana, and Ohio. 136 2012 Residential Electricity Use Per Customer and Average Revenue Per kWh State Five States  California  Connecticut  Minnesota  Rhode Island  Vermont Average States in Which Duke Energy Serves Residential Customers  Florida  Indiana  Kentucky  North Carolina  Ohio  South Carolina Average Average kWh Usage Per Residential Customer Average $/kWh State Residential Electricity Rates 6,878 8,770 9,519 7,168 7,168 7,901 $0.153 $0.173 $0.114 $0.144 $0.170 $0.151 Rate is 38% Higher Than the Average for the Duke Energy States 12,970 11,962 13,559 12,923 10,738 13,424 12,596 Usage is 59% Higher Than the Average for the Above Five States $0.114 $0.105 $0.094 $0.109 $0.118 $0.118 $0.110 Additionally, when looking at total sales per customer, the 59 percent increases to 64 percent due to the higher concentration of industrial use in the Duke Energy states.239 As discussed in Section VIII.A of these comments, the EPA needs to factor differences in customer mix in setting state-level targets for demand-side energy savings. States in which Duke Energy provides service have a higher average use per customer due to a higher concentration of 239 For the five states (CA, CT, MN, RI, and VT), the average use per customer was 18,509 kWh per year in 2012. For the Duke Energy states, the average use per customer was 64 percent higher at 30,270 kWh. The level for the Duke Energy states is higher due to the higher concentration of industrial energy use. 137 industrial economic activity (average 32.5 percent of total load in Duke Energy states versus 20.5 percent of total load in the five states previously referenced). Similar to the conditions that exist in the residential sector, the average price in 2012 for industrial users in the five states previously referenced is 57 percent higher (10.1 cents/KWh) than in Duke Energy states (6.4 cents/KWh). Ignoring state-by-state differences could penalize the industrial sector of the U.S. economy because electricity rates will increase to pay for the cost of the energy efficiency programs. The industrial sector is extremely important to the national economy and it continues to struggle to regain its footing due to the impacts of the 2008 recession. Rising prices can affect the global competitiveness of this sector of the economy and have a disproportionate negative impact on the economies of the states served by Duke Energy. b) Other Factors Including the Enforcement of Building Codes and Customer Opt-Outs Were Not Factored Into the EPA’s Analysis. The EPA’s Proposed Guidelines allude to adopting and enforcing local building energy codes. Historically, public utilities have not enforced state or local building energy codes, and have neither the expertise nor the authority to enforce, verify, and/or analyze energy savings associated with code development and enforcement. However, as the codes and energy savings standards advance, it will become increasingly more difficult for public utilities to create costeffective demand-side energy efficiency programs to meet the EPA’s proposed targets, because most states only allow utilities to incentivize and take credit for the energy savings that are over and above the baselines set by state and local building energy codes. As those baselines increase, the incremental cost of exceeding them will also increase. Even if utilities are allowed to count the savings difference between the customer’s current state (“as found”) and the more efficient piece of equipment, unless there is a drastic shift in the existing laws and regulations in 138 most states, the program would still need to be cost effective based on only the difference between the baseline and the more efficient equipment before it could be offered. As mentioned in Section VIII.A.5 of these comments, the Proposed Guidelines do not take into account the fact that some state regulations allow certain industrial and commercial customers to opt-out of public utility offered energy efficiency programs. The process of opt-out is handled very differently in each jurisdiction. Counting the impacts, if any, related to opt-out is not addressed in the proposal. Further, the Proposed Guidelines do not contemplate who is going to account for energy efficiency for opt-out customers in the future. Historically, public utilities have not counted the impacts associated with opt-out and should not be required to track these savings in the future unless the costs can be recovered from the industrial and commercial sectors through state rate-making mechanisms and only if these savings are counted toward the statewide goal. In its Proposed Guidelines, the EPA has proposed a one-size-fits-all demand-side energy efficiency target based on combining bits and pieces of historical data without performing a detailed analysis of what is achievable in each jurisdiction based on all relevant facts and circumstances that impact the ability to realize demand-side energy savings. Neither the EPA’s proposed 1.5 percent nor alternative 1.0 percent annual energy efficiency growth rates are suitable for across the board application in every state. While Duke Energy believes that the use of demand-side energy efficiency in setting BSER for fossil fuel-fired EGUs under section 111(d) exceeds the EPA’s authority, Duke Energy recommends that if the EPA continues to include demand-side energy efficiency as part of its BSER determination, it should finalize neither the 1.5 percent nor 1.0 percent growth rates and instead, allow each state, with input from impacted utilities, to develop its own demand-side energy efficiency target based on state- 139 specific market potential studies. Market potential studies analyze applicable market conditions within a jurisdiction to develop economically and technologically feasible goals and are an industry accepted practice for determining achievable savings from the adoption of energy efficiency programs. 2. Increasing the Annual Incremental Savings Target to 2.0 Percent Is Not Feasible. Increasing the annual incremental savings rate to 2.0 percent and the pace of improvement to 0.25 percent per year is not feasible. The cost of energy efficiency measures would increase so significantly due to the accelerated depletion of low cost measures, that it is unlikely that most states would be able to scale their programs up to cost effectively achieve a 2.0 percent per year savings levels on an ongoing basis. In fact, Vermont is the only state that has achieved a 2.0 percent per year savings. However, looking at Vermont’s achievements in 2011, 74.7 percent of the impacts came from lighting.240 Repeating this performance is unlikely in Vermont, much less all other states. Therefore, the EPA should not increase the incremental savings target to 2.0 percent and the pace of improvement to 0.25 percent. 3. Alternative Sources of Data Should be Utilized. The data reported on EIA Form 861 contain historical data regarding energy efficiency and demand-side management, but do not provide forward-looking data. As stated above, Duke Energy recommends that the EPA instead allow each state, with input from affected utilities, to develop their own demand-side energy efficiency targets based on state-specific market potential studies. These studies have been conducted on a regular basis by many states and utilities since the 1980s to quantify the size of the energy efficiency resources in their territories and to identify major opportunities for energy savings. Such studies would help states and utilities set 240 See Vermont Public Service Department: Utility Facts 2013, pages EFF4 and EFF5. 140 achievable and cost-effective goals, design efficiency policies and programs, and determine appropriate funding levels for efficiency programs and policies. C. Incorporating Demand-Side Energy Efficiency Measures Under a RateBased Approach. The EPA proposed that demand-side energy efficiency measures may be incorporated into a rate-based approach through an adjustment or tradable credit system applied to an EGUs’ reported CO2 emission rate. The Proposed Guidelines contemplate a process where measures that avoid CO2 emissions from affected EGUs could be credited toward a demonstrated CO2 emission rate for EGU compliance purposes or used by the state to administratively adjust the average CO2 emission rate for affected EGUs when demonstrating achievement of the required rate-based emission performance level in a state plan. The EPA is seeking comments on the different approaches for providing such crediting or administrative adjustment on EGU CO2 emission rates.241 While this is a possible approach to deal with jurisdictional differences, there is a lack of clarity around the calculation methodology, as well as how a rate would be calculated for a utility that operates across state borders. Duke Energy requests that the EPA provide examples of the calculation methodologies for EGUs and fully explain how incorporating demand-side energy efficiency measures under a rate-based approach impacts utilities that operate across state borders. D. Quantification, Monitoring, and Verification of Demand-Side Energy Efficiency Measures. The EPA’s Proposed Guidelines acknowledge that despite a well-defined and generally accepted set of industry practices regarding evaluation, measurement, and verification (“EM&V”), many states with energy efficiency programs use different input values and 241 79 Fed. Reg. at 34,919. 141 assumptions in applying these practices. The Proposed Guidelines contemplate harmonizing state practices by establishing guidance for acceptable quantification, monitoring, and verification of demand-side energy efficiency measures for an approvable EM&V plan. The EPA is seeking comments on the critical features of such guidance, including scope, applicability, and minimum criteria. The EPA is also seeking comment on the appropriate basis for and technical resources used to establish such guidance, including consideration of existing state and utility protocols, as well as existing international, national, and regional consensus standards or protocols. As an alternative to the EPA's proposed approach of allowing a broad range of demand-side energy efficiency measures and programs to be included in state plans, the EPA is requesting comment on whether guidance should limit consideration to only certain wellestablished programs.242 1. Harmonizing State Practices Through a Technical Reference Manual Would Not Be a Constructive Undertaking. Duke Energy opposes the creation of a national Technical Reference Manual (“TRM”) to be included in all state compliance plans that include demand-side energy efficiency measures, to be applied to utility-offered energy efficiency programs. Additional guidance for utilities is unnecessary because EM&V vendors already use nationally accepted protocols (Uniform Methods Protocol, California Standards, International Performance Measurement and Verification Protocol, and others referred to in the EPA State Plan Considerations document) in their evaluation of energy efficiency programs. Also, creating a one-size-fits-all approach does not take into account that each state, and even different jurisdictions within a given state, may have the same energy efficiency measure, but have different inputs to calculation algorithms for the same measure. A TRM would have a limited life-expectancy because it would require 242 Id. at 34,920-34,921. 142 frequent updates to reflect changes in measure level details such as baselines, hours of operation, and operating characteristics. Having a national TRM would simply create an unworkable construct. As acknowledged by the EPA, the utilities, working with their state commissions, have successfully managed the EM&V process for many years without oversight from the EPA.243 This is an area traditionally within the realm of state sovereignty. In addition to state utility commission requirements, utilities must also comply with RTO/ISO requirements, as applicable. Adding another layer of EM&V requirements will increase the complexity and make EM&V more costly, thus hindering the ability of the utilities to develop and offer cost effective programs. 2. Guidance Limited to Well-Established Programs is a Setback to Developing New and Innovative Programs. The EPA requested comments on the option of limiting the eligible types of energy efficiency programs that can be included in a State plan to only a “pre-defined list of wellunderstood program types.”244 Such an approach would be a significant setback to the process of developing new and innovative types of energy efficiency programs. If a program is not allowed to be used as part of a compliance plan, then the utilities and states are unlikely to invest in the development of such programs, and as a catalyst for the adoption of new technologies, this would ultimately be detrimental to market transformation. Moreover, such a limitation is completely in contradiction to the EPA’s goals to increase energy efficiency. 243 244 State Plan Considerations Technical Support Document, June 2014, page 39. Id. at 50. 143 3. The EPA View of Demand-Side Energy Efficiency Measure Life Concept is Incorrect. The EPA discusses applying an expected measure life to the savings from demand-side energy efficiency programs.245 The EPA view on this matter, however, is incorrect because the Agency assumes that when a customer installs a more efficient piece of equipment and that equipment eventually fails and must be replaced, the customer would then install a less efficient piece of equipment than the one being replaced. This is not a reasonable assumption. The concept of measure life should not be included as part of the EPA’s methodology that includes energy efficiency as part of state goals. The EPA should assume that once a customer has adopted a certain energy efficiency measure that the related savings are persistent forever rather than only through the end of the useful life of the equipment. The persistence of these savings represents a “replacement in kind” of the technology, a concept that is widely accepted and practiced in utility system planning. In addition, the EPA has overlooked the interrelationship between utility load forecasts which are affected by historical and projected impacts of energy efficiency and the IRP process. It is that interrelationship that ultimately must be incorporated into any analysis involving the treatment of measure life. The EPA has taken a narrow view of energy efficiency and ignored the fact that utility load forecasts play a role in the setting of efficiency goals related to sales because load forecasts capture the impact of utility energy efficiency programs over time. Utility energy efficiency programs are fundamentally marketing programs designed to encourage consumers to install a higher level of efficiency earlier than they would have installed it without the intervention of the utility programs. In the long-run, the impacts would have happened anyway as a result of changes in codes and standards or as a result of price-driven incentives to 245 Id. at 35. 144 install more efficient equipment upon the end of the useful life of the current technology.246 Those impacts are already captured in the long-run forecast of sales that is a key component of the overall IRP for a utility. The EPA’s proposed methodology would require utilities to not only invest in programs to reduce customer usage equal to some arbitrary percentage of retail sales, but also to re-invest in additional programs to replace savings that were previously achieved through past programs that encouraged customers to adopt more efficient measures and behaviors earlier than they would have anyway. These historical savings should have already been included in the forecast of the utilities future sales as part of the IRP process; therefore, requiring utilities to replace these “expiring” savings would result in a double counting of these same savings and would require utilities to achieve even more than the arbitrary percentage of sales goals the EPA has proposed. To require that utilities must re-invest in higher efficiency measures at the end of their useful life ignores the interaction with utility load forecasts and double counts the impacts. The EPA needs to take a more holistic view on how energy efficiency is used in the utility planning process. 4. Behavioral Demand-Side Energy Efficiency Programs Should Be Included. In its Proposed Guidelines, the EPA suggests that behavioral programs should not be included as acceptable demand-side energy efficiency measures because associated measures have not established a sufficient track record of being widely applied nor widely evaluated through EM&V. Duke Energy and other utilities have implemented behavioral programs for years and performed independent, rigorous EM&V on them. These programs and the EM&V 246 Integrating Energy Efficiency into Utility Load Forecasts, 2010 ACEEE Summer Study on Energy Efficiency in Buildings, by Shawn Enterline (Vermont Energy Investment Corporation) and Eric Fox(Itron Inc.). 145 associated with these programs have been under the oversight of the state public utility commissions in five states where Duke Energy serves customers. The exclusion of behavioral programs will have a significant negative impact on Duke Energy and other utilities that have devoted considerable time and attention to these types of programs. In addition to the impacts driven directly by these behavioral programs, Duke Energy has found that behavioral programs support customer adoption of other programs in our energy efficiency program portfolio. Therefore, Duke Energy recommends that behavioral energy efficiency programs be considered acceptable measures that can be included in state plans. 5. Non-Energy Benefits Should Not Be Included in EM&V. In its State Plan Considerations Technical Support Document, the EPA has proposed allowing a wide set of energy efficiency program and measure types in state plans, as long as the energy savings are adequately documented according to rigorous EM&V methods and subject to appropriate state regulatory oversight.247 Though energy retrofits provide improved comfort and aesthetic enhancements, these non-energy benefits are not easily measured nor valued and the attempt to include them in the valuation of energy efficiency programs will require significant additional spending on EM&V. Duke Energy strongly supports the exclusion of non-energy benefits from the valuation of energy efficiency programs and believes it is better to use a generally accepted value of these benefits embedded within the avoided costs of generation. 6. Line Loss Consistency Should be Included in EM&V. In its State Plan Considerations Technical Support Document, the EPA indicates that it is considering whether or not transmission and distribution (“T&D”) losses should be included in 247 State Plan Considerations Technical Support Document, June 2014, Page 50. 146 the calculation of savings related to energy efficiency programs.248 Duke Energy strongly supports the inclusion of T&D losses in this calculation because it is critical to account for the additional energy savings at a generator that result from reducing a customer’s energy use at their location. The EPA further questions whether or not the calculation of these losses should be included as part of the EM&V process.249 Duke Energy does not support the inclusion of this calculation as part of the EM&V process; rather, this calculation should be performed at the system wide level as a ratio of the total amount of metered generation relative to the total of all metered sales. It is impossible to know which customers may choose to implement which energy efficiency measures; thus, the calculation of losses must be performed at the system level. It is not appropriate to evaluate the system losses through EM&V. 7. Hourly Savings Profile. In its State Plan Considerations Technical Support Document, the EPA acknowledges that energy savings resulting from energy efficiency programs are often expressed in terms of MWh of savings per year.250 However, the EPA suggests that it may be useful to utilize timedifferentiated (i.e., hourly, seasonal) energy savings data to assess the associated avoided CO2 emissions impacts.251 Duke Energy agrees that the timing of when energy savings occur is an important criteria and Duke Energy currently performs all of its cost effectiveness analysis using a methodology that takes into consideration the hourly values of energy efficiency impacts. In addition, the overall hourly savings profiles for the entire expected portfolio of energy efficiency 248 Id. Id. at 51. 250 Id. 251 Id. at 51-52. 249 147 impacts is already used as part of Duke Energy’s IRP process. This process identifies the expected impacts that occur at the estimated time of the overall system peak. This information is used in the valuation of these energy efficiency programs as well as a consideration in the overall system generation plan. 8. Net Versus Gross Reporting of Energy Efficiency Savings. In its State Plan Considerations Technical Support Document, the EPA indicates that it is considering whether energy efficiency savings in state plans should be reported as gross or net of the impact of free riders.252 Duke Energy believes that both views are important for different reasons and would propose that both be reported; however, the gross values should be used for the purpose of determining compliance. 9. EM&V Process for Codes and Standards. The EPA contends that state public utility commissions do not consider the impact of codes and standards as part of their oversight of the utility system planning process.253 However, this is a major consideration in the preparation and review of utility load forecasts in all of Duke Energy’s service territories. Through review of a utility’s load forecast, public utility commissions do consider the impact of codes and standards. Therefore it is not necessary for the EPA to become involved in the examination of codes and standards, nor is it necessary for the utilities to create a separate EM&V process to address codes and standards. Rather, the impacts of codes and standards are independently evaluated as part of the creation of a market potential study. 252 253 Id. at 52-53. Id. at 47. 148 10. EM&V Certification Process. The EPA’s proposed option to qualify eligible EM&V evaluators is duplicative of the current state-level regulatory processes and would introduce an unnecessary additional step to the process. For example, Duke Energy currently selects qualified, independent evaluation vendors to perform evaluation work. The evaluation work products are submitted through a regulatory process that is openly reviewed by regulatory bodies, as well as other interested parties. The utility is already fully motivated to engage with qualified, independent evaluation vendors, because the utility’s performance is placed at risk if an evaluation fails to meet the required level of evaluation rigor, follow industry-accepted methodologies, or demonstrate independent results. Adding a certification requirement will not provide any additional assurance or motivation to meet these expectations. 11. State Plan Documentation. In its State Plan Considerations Technical Support Document, the EPA indicates that EM&V documentation will be an important component of state plans that incorporate energy efficiency programs and measures, because transparency and reproducibility increase overall confidence in reported energy savings results.254 The EPA has presented a possible outline of the types of information that might be included in an EM&V plan for energy efficiency programs and measures included in a state plan. Duke Energy agrees with the EPA that transparency and reproducibility are important and that excessive EM&V documentation requirements may not add value in terms of transparency, and may discourage the inclusion of cost-effective energy efficiency options in state plans. Therefore, Duke Energy encourages the EPA to allow state public utility commissions to identify what is sufficient documentation to support EM&V in their 254 Id. at 58. 149 respective jurisdictions as opposed to the EPA developing a nationwide standard to apply to all public utilities. 12. Treatment of Interstate Effects. The EPA’s proposed rule seeks comments on options regarding interstate effects associated with measures to allow states to take into account the CO2 emission reductions resulting from these programs while minimizing the likelihood of double counting.255 The way the EPA Proposed Guidelines are written, however, energy efficiency and CO2 reduction requirements are calculated on a state basis; but energy efficiency impacts generation requirements that are realized on a cross-state border system basis. Energy efficiency benefits (avoided energy and capacity) impact a utility operating company’s entire system. The generation system for a utility may be located in different states, whereby establishing carbon reduction goals on a state-by-state basis may lead to cross-subsidization between states with respect to energy efficiency program costs. The EPA’s Proposed Guidelines do not include the specifics for utilities in RTOs/ISOs, other than that the RTOs/ISOs will help the states develop their plans. The Proposed Guidelines are so vague on this point that it is difficult to provide meaningful comments regarding RTOs/ISOs and the impact of energy efficiency. Also, the Proposed Guidelines do not differentiate between retail choice states and vertically integrated states, which will greatly impact the extent to which RTOs/ISOs will need to participate. In retail choice states like Ohio, where the utility customers are purchasing retail generation from Competitive Retail Electric Service (“CRES”) providers, it is unclear how the CO2 requirement will be calculated as the CRES provider may be located in a different state. 255 79 Fed. Reg. at 34,921. 150 Therefore, Duke Energy encourages the EPA to develop guidelines that contain sufficient detail so that electric utilities have the opportunity to understand how these rules impact them and their customers before being implemented. The lack of detail in the Proposed Guidelines has the effect of creating significant uncertainty as to how these requirements will impact Duke Energy and in turn, will likely increase the costs of providing electric service. IX. Alternate Goals The EPA has proposed alternate goals that “. . . represent emission performance that would be achievable by 2025, after a 2020-2024 phase-in period, with the interim goals that would apply during the 2020-2024 period on a cumulative or average basis as states progress toward the final goals.”256 The EPA requests comment on the alternate goals, particularly with respect to whether any one or all of the building blocks in the alternate goals can be applied at a greater level of stringency: . . .”257 The alternate goals suffer from the same fundamental flaw as the proposed goals: they are based on an unlawful BSER determination. A standard of performance under section 111 must be achievable by individual regulated sources based on measures that the source’s owner can integrate into the design or operation of the source itself. Building Blocks 2, 3, and 4 are inconsistent with this requirement. Simply lowering the targets of the various Building Blocks doesn’t change this fact. The alternate goals also suffer from the same challenge as the proposed goals in that the interim compliance period, which begins in 2020, does not allow enough time between state plan approval and 2020 to develop and implement a compliance strategy to avoid stranded investments and potential reliability problems. The EPA should not finalize any 256 257 Id. at 34,898. Id. at 34,898-34,899. 151 guidelines that are based on a BSER determination that includes Building Blocks 2, 3, and 4, regardless of the level of stringency of any of the Building Blocks. If, however, the EPA does proceed with finalizing guidelines that are based on a BSER determination that includes Building Blocks 2, 3, and 4, it should finalize goals for 2030 and 2025 without an interim compliance periods, and let each state select whether it will plan to meet a 2030 goal or a 2025 goal. X. The EPA Has Made Numerous Errors in its Goal Calculations That Must Be Corrected and State Goals Revised Accordingly. Duke Energy has reviewed the baseline data, methodology, and calculations that the EPA has used to determine the state-level interim and final CO2 emission rate goals. Based on this review, Duke Energy believes that the EPA has erred either in logical basis or methodology in multiple facets of the calculation. These errors significantly affect the state goals the EPA has proposed. By component of the goal calculation, a description of these issues and the actions that are necessary to correct the problems follow. The numerous errors in many cases significantly affect the state goals the EPA has proposed and the Agency should issue a technical correction to the proposed rule to account for these errors. It would not be enough for the Agency to simply promulgate a new and different set of goals in a final rulemaking; rather, states and other stakeholders must have an opportunity to comment on corrections to the state goal calculations. A. Errors Related to NGCC Facilities in the EPA’s Application of Building Block 2 to State Goal Calculations. 1. The EPA Should Have Used Net Generating Capacity Instead of Nameplate Capacity for Natural Gas Combined Cycle Units in its Application of Building Block 2. In the eGRID baseline data for 2012, the EPA used the EIA860 nameplate MW capacity rating by generator as the basis for any capacity factor or energy production computations. Nameplate capacity represents gross capacity of the generator before any internal plant usage 152 (auxiliary power) is deducted, whereas the net capacity represents the value after auxiliary power is deducted. Net capacity is what a unit can supply to the electrical grid. The EPA is using net MWh generation as the input for emission rate calculations on a pound of CO2 per net MWh basis. Inaccurately and inappropriately, the EPA intermixes the nameplate capacity rating with the net generation when calculating baseline capacity factors for NGCC units. This capacity factor calculation is the basis for the Building Block 2 NGCC redispatch, and the EPA’s use of nameplate capacity when calculating the MWh associated with the redispatch of existing and under construction NGCC units results in an overstatement of potential available net MWh generation that could be added to the electrical grid at a 70 percent NGCC capacity factor (or 15% capacity factor for units under construction).258 To compute the NGCC redispatch, the EPA calculates the MWh generation at a 70 percent capacity factor, using the state total baseline year NGCC nameplate capacity rating (also for NGCC under construction participating in the redispatch at a 15 percent capacity factor).259 While this approach actually yields a gross generation number, a number that is larger than what the NGCC units can actually deliver to the grid at a 70 percent capacity factor, the EPA erroneously calls this “net generation” and then uses it to calculate the increase in NGCC generation from the baseline, which again, is on a net basis. This overstatement of the potential increase in NGCC net generation that would be produced at a 70 percent capacity factor then in turn overstates the amount of baseline coal generation that is being displaced by the increased NGCC generation in the EPA’s methodology. Taken together, the use of nameplate capacity 258 See section VI.B. of these comments for an additional discussion of the problems resulting from the EPA’s incorrect use of nameplate capacity in its calculation of NGCC capacity factors for Building Block 2. 259 EPA-HQ-OAR-2013-0602-0460, Goal Computation Technical Support Document. 153 instead of net capacity results in (1) higher NGCC dilution of the CO2 emission rate goal, and (2) lower coal generation contribution to the CO2 emission rate goal than there should be. As discussed in detail in Section VI.B of these comments, the EPA first erred when it used nameplate capacity instead of net capacity in its evaluation of 2012 NGCC capacity factors. The EPA’s erroneous calculation of capacity factor lead the Agency to settle on a 70 percent capacity factor for the Building Block 2 redispatch, when in reality, the redispatch the EPA used in its state goal calculations for Building Block 2 is more like 80 percent and above based on the correct calculation of capacity factor that is based on net capacity. Instead of using nameplate generator capacity, the EPA should use the net capacity rating of each generator, specifically summer net capacity.260 This will produce a more realistic amount of generation that NGCC units can supply to the grid at a 70 percent (or 15 percent for under construction units) capacity factor (versus gross generation), and also hence what the differential amount of net generation that can be deducted from coal fired units under the application of Building Block 2. The EIA860 database provides reported summer net capacities in addition to nameplate capacity so the information is readily available. Duke Energy notes that for many units in the EIA860 database, net capacity data may be listed by unit (such as for an entire NGCC plant) versus by individual generator (separate capacities for the turbine(s) and the steam generator). In such instances Duke Energy recommends that the plant net rating simply be allocated to the generator level by pro-rata share of generator nameplate gross capacity. Duke Energy recommends the following procedure for replacing generator nameplate capacity with net capacity. 260 The use of summer net capacity is consistent with the EPA’s use of summer net capacity in its IPM modeling for the rule, and will ensure that the net generation potential of NGCC’s will not be overstated. 154  Obtain summer net capacity ratings from EIA860 and append them to the eGRID data, by generator.  For multi-generator units with net capacity identified at the total unit level only, allocate the summer net capacities to the individual generators via pro-rata share of generator nameplate gross capacity.  For NGCC under construction, verify source and type of capacity rating. Confirm that all project values used represent summer net capacity. The approach the EPA has taken is clearly erroneous because it is based on the gross generating capacity. The EPA must correct this error and conduct a proper analysis of the net generating capability of NGCC units in the United States and revise the emissions goals accordingly. 2. The EPA Used Erroneous NGCC Capacity Under Construction Units in its Application of Building Block 2 for Calculating the North Carolina Goals. Building Block 2 of the EPA’s CO2 emission rate goal calculation for North Carolina includes 2,249 MW of NGCC capacity under construction. Duke Energy has traced this number back to the EPA’s NEEDS v5.13 database. 261 This value is in error. With the exception of plants entering service late in the baseline year (2012) and early in 2013 as discussed further below, the only NGCC unit in North Carolina that should be considered under construction was the Duke Energy Sutton NGCC plant This plant was under construction in 2012 and came on line in late 2013. There were no other NGCC units in North Carolina that meet the definition the EPA has established for under construction units; that being “…anything that came on line in 261 The NEEDS v5.13 database has a single 2,249 MW entry for combined cycle in North Carolina with an online year of 2015. There is no county location provided. The plant name is S_VACA_NC_Combined Cycle. 155 2013 or that was under construction, site prep, or testing by January 8, 2014.”262 This is confirmed by a review of open construction permits with the NC Department of Environment and Natural Resources. The Sutton NGCC plant has a net summer capacity rating of 622 MW. The EPA should therefore eliminate the erroneous 1,627MW of NGCC under construction capacity for North Carolina. 3. The EPA Incorrectly Treated Two Duke Energy NGCC Facilities in North Carolina as Existing Units Instead of Under Construction in its Application of Building Block 2. One of Duke Energy’s newly constructed NGCC facilities in North Carolina entered service very late in 2012 (EPA’s selected baseline year). Net generation and CO2 emissions data for the Dan River NGCC facility were first reported to the EPA’s Clean Air Markets Division (CAMD) in December 2012. The total 2012 operating time reported to CAMD for the Dan River NGCC facility in 2012 was less than 10 days. The facility appears in the eGRID database for 2012 with net energy output of 135,081 MWh. This translates to an annual capacity factor of 2.4 percent. Despite this exceedingly low capacity factor due entirely to the fact that the facility was just beginning began operation in late 2012, the EPA took none of this into consideration and treated it as an existing facility for all of 2012. Duke Energy does not believe it is reasonable to treat a facility that was just beginning operation in late 2012 as an existing facility. The Dan River facility was clearly more like an under construction facility for 2012 than an existing facility. Duke Energy recommends that for NGCC units that began initial operation in the base year and did not have a capacity factor of at least 55 percent, the EPA should treat such units as under construction units. Without such a criterion, a facility with as little as one hour of operation in the base year would be treated as an existing facility, which is clearly 262 Goal Computation Technical Support Document at 12. 156 nonsensical. Duke Energy does not believe that it was the EPA’s intent to treat a facility like Dan River as an existing facility. Treating the Dan River unit as an existing unit assigns generation for redispatch that is actually needed to meet generation obligations from the unit that was not reflected in the very limited partial year data. It is clear that under a business-as-usual scenario the Dan River facility was intended to operate at least at the 55 percent annual capacity factor the EPA assumed as the baseline capacity factor for under construction NGCC facilities. Duke Energy therefore believes that the EPA must reclassify the Dan River facility as an under construction facility for purposes of applying Building Block 2 to the North Carolina goal calculation. A second Duke Energy NGCC facility located in North Carolina, the Lee NGCC facility, begin operation in January of 2013, yet has been treated as an existing facility by EPA for purposes of applying Building Block 2 to the North Carolina goal calculation. The facility appears in the 2012 eGRID database with zero net generation and emissions. There was also no data reported to CAMD for the Lee (Wayne County) NGCC facility in 2012. It is therefore clear that the EPA erred in treating the Lee NGCC facility as an existing facility. The EPA must reclassify the Lee NGCC facility in North Carolina to an under construction facility. Using the summer net capacity ratings, the North Carolina new NGCC under construction input value should be composed of (1) Sutton NGCC at 622 net MW; (2) Lee NGCC at 920 net MW; and (3) Dan River NGCC at 620 net MW, for a total of 2,162 net MW. Interestingly, this is very close to the original value of 2,249 MW used by the EPA. However, the EPA has effectively double counted this capacity in the North Carolina goal calculation by also including the Dan River and Lee NGCC facilities as existing facilities. 157 4. The EPA Should Not Include “Under Construction” NGCC Capacity When Implementing Building Block 2 in State Goal Calculations. In calculating each state’s goal, the EPA assumes that NGCC units that were under construction in 2012 have available generating capacity that may be utilized to displace coalfired generation under Building Block 2. Specifically, the EPA assumes that each NGCC unit under construction would operate at a 55 percent annual capacity factor under a “business as usual” scenario in the absence of the proposed emission guidelines.263 This 55 percent annual capacity factor reflects the EPA’s calculation of the “average performance of NGCC units that came online in the past 5 years.”264 The Agency claims it “conservatively designated the generation associated with this 55 percent capacity factor as unavailable for redispatch to reduce CO2 (i.e., not qualifying for Building Block 2), instead, reserving that amount of generation potential to meet other system needs presumed to have motivated the construction” of those units.265 Accordingly, the EPA assumes that an additional 15 percent of the under-construction unit’s nameplate capacity will remain available for redispatch, bringing the unit to an overall annual capacity factor of 70 percent.266 The EPA’s approach is arbitrary and unreasonable. As a general matter, EGUs that commenced construction before January 8, 2014—even those that were “under construction” during the 2012 baseline year the EPA has proposed to use—would be considered “existing units” for the purposes of section 111(d) once completed, and thus could properly be subject to 263 Goal Computation TSD at 12. Id. 265 Id. 266 As detailed in section VI.B. of these comments, the EPA incorrectly calculated the capacity factor of NGCC units by using nameplate capacity in its calculation instead of net capacity. If the EPA were to calculate capacity factors correctly using net MWh generation and net generating capacity), its 70 percent capacity factor would be more in the neighborhood of 80 percent or higher depending on the difference between the nameplate and net capacity of the NGCC units. 264 158 standards of performance contained in a state plan if they meet the relevant applicability criteria.267 But the EPA should not rely on generating capacity from “under construction” units when applying Building Block 2 to calculate the proposed state goals. The EPA has no basis on which to make assumptions about what generating capacity will be available for redispatch from NGCC units that had no operating history in 2012 or earlier. The average annual capacity factor of all recently completed NGCC units,268 is an inadequate predictor of the future generation performance of the individual units the EPA includes in the state goals. Such an average does not account for the fact that some units are constructed for the purpose of supplying base load, while others are constructed as load-following units. Recent experience suggests that the EPA’s methodology grossly overestimates the generation capacity available from units that were under construction in 2012. For example, Duke Energy’s Lee and Dan River NGCC units in North Carolina (which the EPA mischaracterized as “existing” in 2012) operated at an 81 percent and 78 percent annual capacity factor respectively (based on summer net capacity) during 2013, their first year of commercial operation. Yet the EPA’s methodology (assuming the EPA corrects its error and reclassifies these units as under construction as discussed above) would require these units to contribute an additional 15 percent of their nameplate capacity to displacing coal-fired generation, effectively pushing the Lee and Dan River unit capacity factors to 96 percent and 93 percent respectively based on summer net capacities and their 2013 actual capacity factors. 269 Annual capacity factors of this magnitude are certainly unachievable.270 267 See CAA § 111(a)(6). see Goal Computation TSD at 12. 269 The summer new capacities of the Lee and Dan River NGCC units are 920 MW and 620 MW respectively, as reported to the EIA Form 860. 270 The EPA’s treatment of the Lee and Dan River NGCC units as existing resulted in 70 percent of Lee’s output and 67.6 percent of Dan River’s output (based on nameplate capacity) being used to offset generation from coal-fired EGUs in the goal calculation for North Carolina. Because each of these units are already operating at very high 268 159 Given the EPA’s inability to provide a rational justification for predicting the hypothetical operating duty of units that were not operating in the baseline year of 2012, it should exclude “under construction” NGCC units from its application of Building Block 2 for the purposes of calculating state goals. Because these units are technically “existing sources” under section 111, however, they would remain subject to appropriate state plan requirements and would count towards compliance with a state’s interim and final goals if they satisfy the relevant applicability criteria. Another reason why NGCC units classified as “under construction” should not be included in state goal calculations is because they do not meet the applicability criteria for stationary combustion turbines. That is, they would not have supplied one-third or more of their potential electric output to a utility distribution system on a 3-year rolling average basis271 as of 2012. 5. The EPA’s Use of Average 2012 NGCC Emission Rates When Applying Building Block 2 to State Goal Calculations is Inappropriate. When computing the NGCC emissions for the Building Block 2 NGCC redispatch, EPA calculates the additional CO2 emissions from baseline NGCC units using the increase in generation from baseline to 70 percent NGCC capacity factor, at the original baseline year state average NGCC CO2 emission rate. This is again inaccurate and inappropriate, and underestimates the additional NGCC CO2 emissions due to the redispatch. Instead of using the average baseline year NGCC CO2 emission rate, EPA must compute and use the incremental NGCC CO2 emission rate. That is because most of the most efficient, lowest emitting units are already generating at or near the basis 70 percent capacity factor (and have hence significantly capacity factors, it would not be possible for either unit to further increase its capacity factor to produce the additional MWh attributed to them for redispatch in the North Carolina goal calculations. 271 79 Fed, Reg. at 34,954, Proposed 40 C.F.R. § 60.5795(b)(2). 160 influenced downward the baseline average CO2 emission rate), whereas the units that would actually be redispatched and contribute the most increase in net generation are the less efficient, higher emitting units. The incremental emission rate of these higher emitting units must be used to estimate the additional CO2 emissions from the redispatch. To compute the state average incremental NGCC CO2 emission rate requires an analysis of the eGRID baseline data at the generator level. The EPA cannot summarize the data to the state level first, and then perform the calculations. After appropriately determining the generator net capacity ratings as described above, the EPA must calculate and review generator-bygenerator the baseline capacity factor, CO2 emission rate, and potential contribution of each to the redispatch. To compute the state average NGCC redispatch incremental CO2 emission rate, Duke Energy recommends the following procedure.  For each NGCC generator, calculate the baseline year net capacity factor using the eGRID net generation and the summer net capacity rating. Subtract this number from 70 percent to determine the net capacity factor increase (or decrease) available. If a generator was operating above 70 percent net capacity factor in the baseline year, Duke Energy believes that it is appropriate to adjust this downward to the 70 percent target.  For each affected NGCC generator, calculate the baseline year average CO2 emission rate by dividing the CO2 emission (in tons) by the net generation MWh, times 2000 to convert to pounds.  For each NGCC generator, calculate the number of annual net generation MWh available for redispatch using the net capacity factor increase available, and the summer net capacity rating of the unit. 161  For each NGCC generator, calculate the number of annual CO2 emissions increased (or decreased) by multiplying the baseline year limited CO2 emission rate by the number of annual net MWh available for redispatch.  Now for each state, accumulate the total number of annual net generation MWh available for redispatch from all NGCC generators, and the total number of annual CO2 emissions changed from all NGCC generators.  For each state, divide the accumulated annual CO2 emissions by the accumulated annual generation available. This is the incremental NGCC CO2 emission rate. Use this in place of the baseline year average NGCC CO2 emission rate when computing the CO2 emission increase from NGCC units due to the Building Block 2 redispatch. 6. The EPA Must Exclude NGCC Units that Do Not Meet the Applicability Criteria for Stationary Combustion Turbines from State Goal Calculations. Under section 111(d), state plans may establish standards of performance only for “any existing source . . . to which a standard of performance under this section would apply if such existing source were a new source.”272 In this case, the Proposed Guidelines may be used only to establish standards of performance for existing EGUs that otherwise meet the eligibility criteria for EPA’s proposed NSPS for GHG emissions from new EGUs.273 The NSPS for new EGUs applies to any stationary combustion turbine that, inter alia, has a base load rating greater than 73 MW (250 MMBtu/h) . . . and was constructed for the purpose of supplying, and supplies, onethird or more of its potential electric output and more than 219,000 MWh as net-electrical sales 272 273 CAA § 111(d)(1)(A)(ii). 79 Fed. Reg. at 1,430. 162 on a 3 year rolling average basis.274 Therefore, EPA’s Proposed Guidelines may deal only with regulation of existing Subpart KKKK stationary combustion turbines that meet these same criteria.275 It is clear from the Proposed Guidelines, however, that EPA disregarded these applicability criteria and applied the BSER building blocks to units that do not meet the applicability criteria when determining each state’s obligations. In particular, it appears that the EPA made no effort to exclude from the Proposed Guidelines NGCC units that did not “. . . suppl[y], one-third or more of [their] potential electric output and more than 219,000 MWh netelectrical output to a utility distribution system on a 3 year rolling average basis.”276 Including NGCC units that did not meet the one-third sales exclusion in the goal calculation artificially inflates the amount of NGCC generating capacity that is available for redispatch, which thus inflates the amount by which coal-fired EGUs must reduce generation under Building Block 2. Once this inflated redispatch is incorporated into a state’s goal, affected NGCC units will be forced to operate at capacity factors significantly above 70 percent in order to accommodate the expected generation that states cannot require from non-affected EGUs. With respect to Indiana, using the summer rated net capacity of the Noblesville NGCC facility of 285 MW,277 the facility would have needed to generate 826,135 net MWh in 2012 to operate at a 33 percent annual capacity factor. The Noblesville NGCC facility generated 274 Proposed 40 C.F.R. § 60.4305(c), 79 Fed. Reg. at 1506. See CAA § 111(d); 40 C.F.R. § 60.21(b). 276 79 Fed. Reg. at 34,954, Proposed 40 C.F.R. § 60.5795(b)(2). 277 Using the summer rated capacity for this calculation is conservative because it is lower than the winter rated capacity (310 MW) and nameplate capacity (328 MW) so it will produce the smallest net MWh generation that equates to a 33% annual capacity factor. See the 2012 EIA-860 generator database for the unit’s summer and winter rated capacities. See the EPA’s 2012 e-grid database for the unit’s nameplate capacity. 275 163 820,513 net MWh in 2012.278 In 2010, the facility generated a total of 227,093 net MWh,279 and in 2011 the facility generated a total of 350,091 net MWh. This results in a three year average capacity factor over the period 2010 –2012 of 18.6 percent. Clearly this unit does not meet the “and supplies, one-third or more of its potential electric output on a 3 year rolling average basis” criteria for the unit to be a 111(d) affected unit. The EPA should therefore recalculate the Indiana state goal without the Noblesville facility. B. The EPA Should Not Give Further Consideration to the Goal-Setting Methodology Presented in the October 30, 2014 NODA. The EPA’s NODA solicits comment on whether the EPA should alter its goal computation methodology in order to reduce generation more drastically from existing fossil fuel-fired EGUs. The Agency neither proposes this change in the NODA nor did it propose such an approach in the June 2014 Proposed Guidelines. Specifically, the EPA solicits comment on an alternative approach in which “incremental RE and EE explicitly replaces generation from fossil fuel-fired sources in the goal calculation.”280 There are several problems with this approach. First, the EPA has no authority to establish a standard of performance under section 111 based on reduced utilization (or retirement) of a source. Second, if the EPA wishes to pursue such a dramatic change in its Proposed Guidelines, it must undertake a thorough evaluation of costs and other implications, as required by section 307(d)(3) of the CAA, and allow the public a sufficient period of time to evaluate and comment on those studies. It is highly likely that here will be significant costs, including additional stranded assets, as well as additional threats to the reliable supply of 278 See the EPA’s 2012 eGRID database. See the EPA’s 2010 eGRID database. 280 79 Fed. Reg. at 64,552. 279 164 electricity It is not possible to evaluate these issues without the additional analyses that EPA has failed to undertake. Third, beyond the likely very high additional costs, this alternative approach seems at odds with the EPA’s apparent overarching goal of reducing generation from all fossil fuel-fired EGUs because it would have the counterintuitive effect of encouraging the construction of additional new fossil fuel-fired EGUs relative to the EPA’s June 2014 Proposed Guidelines. According to the EPA, the rationale for its proposed goal computation approach was that the additional RE and EE would replace expected generation increases from fossil sources that otherwise occur after 2012.281 In other words, RE and EE would be used to meet future generation needs, while leaving the existing fossil EGUs to continue serving existing (i.e., pre2012) load demand. The alternative approach described in the NODA would require that incremental RE and EE be used first to satisfy existing (i.e., pre-2012) demand by displacing generation from existing fossil EGUs. 282 If the incremental RE and EE encouraged by the Proposed Guidelines is dedicated to meeting historical demand, any post-2012 increases in demand will need to be met by other sources, most likely fossil fuel-fired EGUs because the proposed goals for RE and EE under Building Blocks 3 and 4 are already extremely aggressive. Therefore, a likely outcome of the alternative approach discussed in the NODA would be to encourage the use of new fossil generation to satisfy future demand rather than RE—a policy outcome that seems to be at odds with the EPA’s overall goals. 281 282 Id. Id. 165 XI. The EPA Should Use a Multi-Year Historic Baseline Period for State Goal Setting. In its Goal Computation Technical Support Document283 the EPA states that it “carefully considered using a historic year data set, a projected year data set, or a hybrid of the two as a starting point…for calculating the state’s emission rate goals” but “chose the year 2012 as it represented the most recent year for which complete data were available at the time of the analysis.” The EPA goes on to state that it “also considered the possibility of using average fossil generation and emission rate values over a baseline period (e.g., 2009 – 2012), but determined that there would be little variation in results compared to a 2012 base year data set due to the rate-based nature of the goal.”284 Duke Energy agrees with the EPA that a historic baseline is preferable to a projected year or a combination of historic and projected, but we do not agree with the EPA’s decision to use a single year, 2012, as the starting point for calculating the state’s emission rate goals. The EPA has offered no data or analysis to support its stated finding that there would be little variation in results using a 2009 – 2012 baseline period compared to a 2012 base year. If the EPA made this determination by actually calculating individual state baselines for the 2009 – 2012 period and comparing them to the 2012 baseline for each state, they should have presented the information for public review and comment. Lacking that information, there is no way to know how the Agency made that determination. In addition, without the ability to examine the data, it is unclear how EPA defines “little variation.” Finally, the EPA fails to explain how the “rate based nature of the goal” is responsible for the “little variation in results” the EPA states exist between a 2009 – 2012 baseline and a 2012 baseline, as its statement implies. 283 284 EPA-HQ-OAR-2013-0602-0460 at 4. Id. 166 Duke Energy believes it is inappropriate to use any single year as a baseline to represent the electric power sector. Sources and amounts of electricity generation can and do vary from year to year. The variability is due to many factors that include economic conditions, weather variability, year-to-year fluctuations in fuel prices, and significant unplanned and planned unit outages. With regard to fuel prices, natural gas prices in 2012 were at their lowest level since before 2000 (the 2012 annual average Henry Hub price was $2.75 per mmBtu), lower than today’s price, and lower than any natural gas price the EIA projects into the future. This one fact alone disqualifies 2012 as a single baseline year to represent the electric power sector. The EPA clearly recognizes that there is year-to-year variability in the electric power sector, and has taken steps in previous power sector rulemakings to address it. For example, as part of the EPA’s Cross State Air Pollution Rulemaking (CSAPR)285 regulating SO2 and NOx emissions from the power sector, the EPA believed that the power sector variability was significant enough that it prepared an entire Technical Support Document286 specifically to address the issue, and included provisions in CSAPR to address that variability.287 In the Proposed Guidelines, the EPA also acknowledges that there is “…year-to-year variability in economic and other factors, such as weather, that influence power system operations and affect EGU CO2 emissions,”288 yet the EPA makes no mention of power sector variability with respect to its proposal to use 2012 as the single baseline year. Duke Energy believes the failure of EPA to address power sector variability in its selection of a baseline period is a gross oversight that must be corrected. 285 Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approval. 76 Fed. Reg. at 48208 (August 8, 2011). 286 Power Sector Variability Final Rule TSD, July 2011. EPA-HQ-OAR-2009-0491-4454. 287 The EPA based emission allowance allocations under CSAPR on affected unit heat input for multiple years, as it did in the Clean Air Interstate Rule, and the NOx SIP Call rule. 288 79 Fed. Reg. at 34,906. 167 The use of 2012 as the single-year baseline also limits the ability of states to receive credit for early actions that reduce CO2 emissions, such as the retirement of coal-fired EGUs. Coal-fired EGUs that retired during the period 2009 – 2011, for example, would not be recognized under the EPA’s proposed 2012 baseline. A multi-year baseline would allow states to capture and get credit for more early actions in their implementation plans than using 2012 as a single year. The EPA made 2010 and 2011 eGRID data available as part of its October 30, 2014 Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units Notice of Data Availability.289 Duke Energy used that data to calculate CO2 emission rates for each year for the states in which it operates, using the same methodology the EPA used to calculate 2012 CO2 emission rates for each state. Duke Energy found that the use of either 2010 or 2011 would in fact produce significant changes to state baselines that would be carried through to significant changes in some state goals. For the reasons cited above, Duke Energy recommends that the EPA use a multi-year baseline consisting of 2009 through 2012.290 Specifically, the EPA should calculate state’s baselines for each of these years and select for each state’s baseline the average of their highest three of four years. This will produce a far more representative baseline for the utility sector than any single year. Again, all the EPA has offered with respect to a multi-year baseline is that it “also considered the possibility of using average fossil generation and emission rate values over a baseline period (e.g., 2009 – 2012), but determined that there would be little variation in results compared to a 2012 base year data set due to the rate-based nature of the goal.” This one 289 Id. at 64,543. While the EPA failed to make 2009 eGRID data available as part of its October 30, 2014 NODA, Duke Energy believes that 2009 should be included in a multi-year baseline period. 290 168 statement, unsupported by any data or analysis, is hardly justification for the EPA to not use a multiple year baseline period and it makes the EPA’s selection of 2012 as the baseline arbitrary and capricious. XII. Monitoring, Recordkeeping and Reporting The EPA proposes to require that state plans include monitoring provisions for EGUs that are no less stringent than those in its Proposed Guidelines at Subpart UUUU §60.5805. According to the EPA, monitoring under Part 75 and reporting to the EPA’s Emission Collection and Monitoring Plan System (“ECMPS”) would generally satisfy those requirements, with only a few exceptions.291 The Proposed Guidelines require that an affected EGU must measure the hourly CO2 emissions from each unit and the hourly net electric output from each unit. (Units which share a common stack and are subject to the same emissions standard may be reported at the common stack level.) A. Measurement of CO2 Emissions. The Proposed Guidelines limit the use of the alternatives available in Part 75 for measuring CO2. The Proposed Guidelines appropriately include two of those alternatives – installation of CEMS including a CO2 concentration monitor and flue gas flow rate monitoring system, and for liquid or gaseous fuel-fired units the option of using Part 75 Appendix G procedures to determine CO2 mass emissions. However, Duke Energy does not understand why EPA has specifically required use of a CO2 CEMS (and not allowed use of an O2 CEMS to obtain CO2) at an EGU. Both existing NSPS applicable to EGUs—Subparts Da and KKKK— allow use of either a CO2 concentration monitor or an O2 concentration monitor as the diluent monitor to calculate emissions in lbs. per mmBtu. In addition, Part 75 explicitly allows use of an 291 79 Fed. Reg. 34,913. 169 O2 concentration monitor to measure CO2 concentration to obtain CO2 mass emissions. There is no justification for not allowing both types of monitoring systems under this rule as well. Although most coal-fired EGUs opt to use CO2 concentration monitors, there are valid reasons an EGU (particularly a gas- or oil- fired EGU) might prefer an O2 monitor. Oxygen analyzers generally cost less, are more stable, and are less affected by interferences (e.g., H2O and CO) that can impact CO2 measurements. The EPA could easily add an option for use of an O2 monitor simply by adding a reference to §75.10(a)(3)(iii) in proposed Subpart UUUU §60.5805(a)(2). Duke Energy has installed O2 monitoring systems which meet the Part 75 monitoring requirement on many of our combined cycle facilities. O2 monitoring is also commonly used for regulatory reporting to meet other permitting requirements, such as average NOx or CO emissions adjusted to a normalized O2 concentration. Duke Energy also is concerned that the proposed language requiring EGUs that measure CO2 concentration on a dry basis to “install, certify, operate, maintain, and calibrate a continuous moisture monitoring system” under §75.11(b), Proposed Subpart UUUU §60.5805(a)(2)(i), could be interpreted as eliminating the option in §75.11(b)(1) to use appropriate default moisture values rather than installing and calibrating a monitoring device. The Part 75 default moisture values for coal and wood were derived from the Agency’s own evaluation of data in a 1999 rulemaking in which the Agency determined that they were sufficiently conservative to ensure no under-reporting.292 The EPA approved the default moisture value for natural gas (boilers only) in 2008 based on data submitted to the EPA.293 Duke Energy can think of no reason why the EPA would eliminate this option for existing units, and hopes that it was not the EPA’s intent 292 293 64 Fed. Reg. 28,564, 28,567, 28,568, 28,590 (May 26, 1999). 73 Fed. Reg. 4312, 4315, 4342 (Jan. 24, 2008). 170 to eliminate use of the default values. Duke Energy recommends that instead of the proposed language, the EPA revise the wording as follows: If an affected EGU measures CO2 concentration on a dry basis, they must also determine the moisture content as described in § 75.11(b) of this chapter. If the Agency has a reason for eliminating the O2 monitoring and moisture default value options for either coal-fired EGUs or liquid and gas-fired EGUs, it must issue a rulemaking proposal identifying that reason so that stakeholders can comment on the Agency’s rationale. Existing EGUs will still need to comply with the Acid Rain Program and eliminating these options in state plans effectively eliminates them in Part 75. For EGUs using CEMS, the EPA proposes a new requirement to measure the dimensions of each stack or duct at the flow monitor and reference method sampling location using a laser device.294 Duke Energy objects to this provision. The EPA’s rulemaking record contains no evidence that existing methods are not sufficiently accurate, and no evidence that laser devices would provide significantly more accurate results. As a result, it appears that the requirement imposes additional cost and burden with no corresponding benefit. If the EPA has evidence to support this proposed requirement, it should provide it. B. Monitoring and Reporting of Electric Output. To determine compliance with the proposed output-based standards, the EPA proposes to require installation of a sufficient number of watt meters to measure “net electric output” from the facility, as well as specifying special provisions for combined heat and power (“CHP”) facilities and process steam applications.295 For the first time, the EPA also proposes to require that these electrical measurements be made using “0.2 class electricity metering instrumentation 294 295 Proposed Subpart UUUU §60.5805(a)(2)(iii). Proposed Subpart UUUU §60.5805(a)(4). 171 and calibration procedures as specified under [American National Standards Institute (“ANSI”)] Standards No. C12.20.”296 Duke Energy’s concerns with these requirements are addressed below. 1. Monitoring of Net Electrical Output Should Not Be Required. The EPA’s Proposed Guidelines for affected sources should include monitoring and reporting based on gross MWh rather than net MWh. First, because Congress assigned the states with primary authority for implementing the 111(d) guidelines, the EPA has no authority to establish these specific monitoring requirements. The EPA’s requirement to report net MWh is not consistent with how the affected source is defined, and places a regulatory burden on equipment and processes that are outside the boundaries of the affected source. While it is true that power generating facilities are typically equipped with devices to measure and report auxiliary power use (to provide appropriate FERC accounting of energy production and supply), the EPA’s assertion that its proposed monitoring and reporting requirements will not be burdensome is incorrect. Adding a requirement to monitor auxiliary electrical usage will subject many more plant metering systems to additional procedural and paperwork requirements, and therefore will subject these non-affected sources to compliance obligations which are not authorized by the CAA. The EPA can no more require monitoring under Proposed Subpart UUUU §60.5805 for non-affected sources at a facility that includes affected EGUs than it could require other non-affected sources (such as nuclear power plants, renewable power facilities, or even residential home electrical usage, which are all included in various parts of the EPA’s proposed Building Blocks) to install and maintain specific electrical metering devices. States should retain the flexibility to determine how they will implement the Proposed Guidelines, and 296 Id. 172 that flexibility will include whether the state should require specific monitoring and reporting from facilities or entities that are not otherwise affected sources under the terms of 40 CFR 60. 2. Requiring the Use of ANSI Standard C12.20 Is Not Justified. The EPA has proposed that electrical metering for all systems used to report net MWh electric generation must meet specific ANSI Standard C12.20 instrumentation and calibration procedures. Newer power generating stations or stations that have replaced older metering equipment may be capable of meeting that standard, but there are many stations where some or all of the equipment will not meet ANSI Standard C12.20 requirements. The EPA has not provided justification for that proposal in this rulemaking. In a TSD included in the docket, the EPA says only that the requirement “would ensure a level playing field regarding the minimum acceptable accuracy of equipment … while minimizing any additional burden of upgrading equipment used to measure net generation.”297 However, the EPA has not provided any information to suggest that all EGUs are not already using meters of acceptable accuracy or that requiring compliance with the ANSI standard would not impose additional burdens or require the upgrading of equipment. The EPA has never before found it necessary to impose such requirements because EGUs already have sufficient incentives to ensure that the electricity they generate and use is accurately measured. Compliance with that proposed requirement would be burdensome. Although EGUs may have some meters that comply with all or parts of the ANSI standard, many of the meters, including many meters installed at Duke Energy EGU facilities, do not and the cost of replacing such meters is not insignificant. Moreover, the ANSI standard itself is extraordinarily detailed and not at all suited to a regulatory program under which penalties could be sought for a failure 297 Technical Support Document: Part 75 Monitoring and Reporting Considerations, Docket ID No. EPA-HQ-OAR2013-0602-0461 (“Part 75 GHG Guideline TSD”). 173 to comply. The EPA has not provided a copy of the standard in the docket, or even discussed the content of the standard in any meaningful way. In fact, the ANSI standard is not even publically available and must be purchased from ANSI , which charges a significant sum for access to the standard and restricts the networking and transferring of the purchased file to another person or computer.298 With respect to the monitoring of net electric output, the EPA’s proposal appears to be based on an assumption that net output would be determined using existing equipment and simple apportionment schemes.299 Duke Energy agrees that if the monitoring of net electric output is required, the EPA must allow EGUs to use existing equipment and methods for metering station service, and to apportion common station service to individual units based on unit generation.300 But the EPA’s proposal to require adherence to ANSI Standard C12.20 will, in fact, require many EGU facilities to replace existing equipment at considerable cost. If the EPA were to require replacement of existing equipment or to impose more stringent standards on existing equipment, the EPA would need to revise its proposal to estimate and solicit input on the additional costs and burdens of such metering. Because auxiliary support facilities are outside of the boundary of the defined affected emissions source, the EPA does not have the authority to require upgrade of auxiliary power usage metering systems. In addition, the specific requirement to apply ANSI Standard C12.20 to auxiliary power meters is not justified because the incremental gain in accuracy would be inconsequential. Auxiliary power usage accounts for less than 10% of gross electric generation 298 See http://webstore.ansi.org/FindStandards.aspx?SearchString=C12.20&SearchOption=0&PageNum=0&SearchTermsA rray=null%7cC12.20%7cnull. 299 Part 75 GHG Guideline TSD at 3 (“EPA understands that the equipment needed to convert gross generation to net generation on an hourly basis exists at all EGUs.”). 300 Id. at 3-5. 174 and a small improvement in accuracy will have an inconsequential impact on the reported net generation. The EPA is micromanaging a decision that is left to the states. 3. Monitoring and Reporting of Useful Thermal Output. The EPA solicits comment on whether it should specify “best practices” for measurement of useful thermal energy and quality assurance protocols to ensure consistent and accurate reporting, “while minimizing additional burden.”301 Duke Energy does not believe that it would be appropriate for the EPA to specify which technologies to use or to impose requirements for periodic quality assurance (“QA”). Any accuracy gains that might be achieved from imposing additional requirements surely would be lost in the noise of the calculations and assumptions used to justify the percent credit for thermal output.302 Identifying “best practices” may be well-intended, but decisions on appropriate measures each facility will take to provide what it believes are accurate measurements are best left to the engineers responsible for the facility. Each EGU should be allowed to select the technologies that best suit its needs under the circumstances, and to determine the best mechanism to ensure an appropriate level of accuracy. The steam supply systems are unique to each facility, and measurement technology decisions will consider many factors. Different types of meters, instruments, and calculation methods also provide varying levels of accuracy depending on the steam conditions, which can vary from source to source. For example, some steam is supplied, and therefore metered, at conditions that are barely superheated or barely at the saturation temperature. Moreover, some equipment simply would not benefit from any periodic QA. For 301 Id. See, e.g., Memorandum to Docket, Credit for Thermal Output at Combined Heat and Power (CHP) Facilities, Docket ID No. EPA-HQ-OAR-2013-0495-0070. 302 175 example, thermocouples and resistance temperature detectors either work or fail completely. Because removing such sensors for calibration may be difficult, and even dangerous in high pressure processes, there is no benefit to removing them until they fail and have to be replaced. Manufacturers’ recommendations also are not universally appropriate for ongoing maintenance or QA, and are not appropriate for use in rules because they vary from vendor to vendor and can change over time without any opportunity for the regulated community to comment on the impact of any changes in the recommendations. The EPA has not provided any details of what requirements, procedures, or specifications that it may consider to be reasonable best practices. Further rulemaking, supported by analysis of the possible requirements and impacts, needs to be proposed for public comment before EPA can issue any final requirement. 4. Monitoring Plan and Quality Assurance and Quality Control (“QA/QC”) Testing. The EPA proposes to require preparation of a site-specific monitoring plan consistent with 40 C.F.R. §75.53(g) and (h) and that “each monitoring system . . . meet the applicable certification and quality assurance procedures in §75.20 … and Appendices B and D to part 75.” (It appears that the references to Appendices B and D are incorrect and the sentence should read “Appendices A and B.”) Proposed Subpart UUUU §60.5805(a)(1), (2)(ii). The EPA also says that it is considering requiring that the Part 75 monitoring plan include “the reporting of equipment used to measure net electric output (and net energy output for CHP units) in an EGU’s monitoring plan under [Part 75].”303 The EPA also is considering requiring the reporting 303 Part 75 GHG Guideline TSD at 7. 176 of the results of any new QA/QC test on equipment used to measure net electric or energy output to the Emission Collection and Monitoring Plan System (“ECMPS”).304 Duke Energy supports the use of Part 75 for preparation of a monitoring plan for systems to measure and record CO2 mass emissions and submission of that plan to ECMPS. However, Duke Energy does not believe that there is any benefit to including equipment used to measure electric and energy output in the Part 75 monitoring plan or to requiring additional QA/QC for that equipment. EGUs already have sufficient incentives to ensure that their equipment for measuring output is accurate, and the EPA has not provided any information to suggest that additional quality assurance is warranted. Duke Energy also believes that any increase in accuracy would be dwarfed by other sources of allowed error in the overall measurements that cannot be eliminated. On the other hand, the resources necessary to track such equipment, to purchase and install new equipment if necessary to meet new accuracy standards, and to perform such testing would be significant. 5. Use of Specific Methods for Flow RATAs and Baseline Adjustments Following a Change in Method. The EPA proposes to require that if an EGU chooses to use Method 2 to perform the required relative accuracy test audit (“RATA”) on a flow monitoring system, the EGU must use a calibrated Type-S pitot tube (rather that the default Type-S pitot).305 However, the EPA also solicits comment on requiring use of what it calls “the most accurate RATA reference method for specific stack configurations” when performing tests on stack gas flow monitors, and use of a “computational adjustment” when an EGU changes RATA reference methods.306 304 Id. Proposed Subpart UUUU §60.5805(a)(2)(v). 306 79 Fed. Reg. at 34,915. 305 177 Approved methods for flow RATAs under Part 75 include Methods 2F, 2G, 2H, and conditional test method (“CTM”) 041. Method 2F uses a three dimensional (“3-D”) probe to determine yaw angle, pitch angle, axial velocity, and volumetric stack flow. Method 2F was developed to eliminate high bias of stack flow measurements in stacks with cyclonic flow. Method 2H and CTM-041 provide procedures for adjusting stack flow measurements to correct for velocity decay near a stack or duct wall that is not present in the measurements taken elsewhere in the stack.307 In the Part 75 GHG Guideline TDS at 7-8, the EPA expresses concerns that allowing sources to use these alternative methods (and in particular allowing EGUs to change methods over time) could lead to inconsistencies between emissions or heat input values. To avoid this result, the EPA solicits comment on whether it should require use of the more accurate methods, and whether it should develop adjustment factors for normalizing data when an EGU opts to use a different reference method to calibrate its stack flow monitor during a RATA. Although the EPA must allow use of Methods 2F and 2H (or CTM-041), it should not require the use of either one. First, not all EGUs will obtain more accurate measurements using these methods. EGUs with axial flow and smooth stack liners may not experience any improvement in flow measurements from either method, each of which is designed to correct for non-axial flow and wall effects caused by friction. Although the methods can provide more accurate (and lower) stack flow measurements for other EGUs, they also impose additional burdens. Any EGU concerned about overestimation of measured flow due to cyclonic flow 307 Methods 2F and 2H, which address stacks and round ducts, are codified at 40 C.F.R. Part 60, Appendix A-1 and A-2, respectively. CTM-041 addresses wall effects in square ducts. Although EPA has proposed to revise Method 2H to reflect the CTM-041 procedure for square ducts, 74 Fed. Reg. 42,819 (Aug. 25, 2009), EPA has not yet finalized it. 178 conditions, or wall effects, can opt to use either method. There is no basis, however, to require their use. The EPA also should allow use of Method 2G. Method 2G uses a 2-dimensional probe to measure yaw angle (but not pitch) and near-axial velocity. Method 2G also can provide more accurate (i.e., lower) flow measurements than Method 2 under some conditions.308 Method 2G is often performed using an auto-probe, which can reduce testing time. Part 75 allows use of Methods 2, 2F, 2G, 2H, and CTM-041.309310 EGUs should be allowed to choose which version of the flow method is best for the particular application and should not be required to perform 3D testing where it is not needed. Regarding the EPA’s suggestion that it develop “adjustment factors” that would be applied if an EGU changed flow methods, the EPA has not provided sufficient information to justify such a requirement. The EPA’s example – that a unit that transitions from Method 2 to Method 2H when performing flow RATAs would apply a “percentage reduction of baseline data” – is unclear.311 Specifically, it is not clear what data the EPA is suggesting would be altered – the baseline data used in setting the state goal or data used to determine compliance under an approved state plan. The EPA’s suggestion that data would be “reduced” by some percentage suggests that the EPA’s reference is to baseline data. But that would seem to require recalculation of the state goal every time an EGU changed flow RATA methods. The altering of data collected under Part 75 could have serious consequences and Duke Energy certainly would object to the use of such altered data for any other program. The EPA also does not provide a timeframe for this requirement. If the EPA is suggesting that the compliance data – not baseline 308 40 C.F.R. pt. 60, App. A-2. 40 C.F.R. pt. 75, App. A- 6.5.10. 310 Currently, to use CTM-041, EGUs must submit a one-time written request to EPA. See EPA, Rectangular Duct Wall Effects, http://www.epa.gov/airmarkets/emissions/rect-wall-ducts.html. 309 311 Part 75 GHG Guideline TDS at 7-8. 179 data – be altered, there would be no adjustment needed for data collected prior to implementation of the state plan, or for changes in methods made before 2012. Finally, the EPA has not provided any information to inform how it might calculate an adjustment factor. Since the impact of a change in flow methods would be site specific, the EPA presumably would have to require a comparison of flow data collected with the CEMS before and after the RATA. But that is hardly a concept that is sufficiently developed to allow for meaningful comment. In short, the two sentences of vague conceptual language in the Part 75 TSD is not sufficient to inform commenters of the scope or impact of the EPA’s proposal. If the EPA intends to pursue such a requirement, it must issue a rulemaking proposal that fully explains what kind of adjustment it is proposing and specifically how the percentage value would be determined. The vague concepts the EPA has discussed are troubling because they suggest that the EPA might set a Guideline that is in effect a moving target, not just for an individual EGU but for all the interrelated sources and entities that are tied to a state’s implementing regulations, and even beyond the borders of a state where the recalculated state emissions goal would have repercussions for any agreements with other states. Duke Energy recommends that the EPA simply not pursue this issue of “adjustments” to baseline calculations. 6. EGU Recordkeeping Requirement. The EPA proposes to require that EGUs maintain records for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record, and that those records be kept “on site” for at least 2 years.312 Duke Energy opposes the proposed 10-year record retention period for all of the supporting information, unless the EPA can show a special need as required under the Paperwork 312 Proposed Subpart UUUU §60.5805(b). 180 Reduction Act regulations.313 To the extent the EPA or a state intends to audit the accuracy of a certified report by reference to supporting information, the EPA should do so within a reasonable period of time (e.g., 3 years). Absent an audit, the data have little or no usefulness. Part 75 has a 3-year record retention requirement, and the EPA has not provided any information to suggest that has been inadequate.314 Given the EPA’s proposed reliance on Part 75 monitoring, compliance with Part 75 recordkeeping should be sufficient for approval of a state plan. Duke Energy also opposes the proposed on-site retention requirement if it means that retention of electronic records that can be accessed “onsite” (even if they are physically located offsite) would not be adequate. Many of the records to be retained are recorded only in electronic form and, depending upon the facility’s management practices, may be retained at a central location in order to facilitate backups and other services. As long as the facility can access the information onsite, there is no reason for it to be located there in a paper hardcopy form. XIII. The EPA Must Provide Greater Clarity Around the Approach it Envisions for States to Perform Rate-to-Mass Translations. The EPA has proposed that the rate-based CO2 emission performance goals may be converted to mass-based emission performance goals.315 The EPA provides an explanation in the “Projecting EGU CO2 Emission Performance in State Plan Technical Support Document”316 of how such a translation would be made. While the explanation in the TSD is a less than clear explanation of how the translation should be performed, based on comments made by EPA staff on this matter it would appear that what the EPA contemplates is that states wishing to make a 313 5 C.F.R. §1320.5(d)(2)(iv). 40 C.F.R. §75.57(a). 315 Id. at 34,953. 316 EPA-HQ-OAR-2013-0602-0462. 314 181 rate-to-mass translation would employ a model such as IPM or other similar type model to project a state’s compliance with its rate-based limits and pull from the model output for each year from 2020 to 2029 the total projected CO2 emissions for the universe of affected sources, with the result being the state’s equivalent mass-based cap. Assuming this is generally correct, the procedure in § 60.5770317 of the proposal would appear to contradict this approach. It states that “(3) The conversion must represent the tons of CO2 emissions that are projected to be emitted by affected EGUs, in the absence of emission standards contained in the plan, if the affected EGUs were to perform at an average lb. CO2/MWh rate equal to the rate-based goal for the state identified in Table 1 of this Subpart.” While it may not be what the EPA intended, this language could be interpreted as directing a state to multiply the MWh generation projected by a model by the state’s emission rate goals for each year and that would be the equivalent massbased cap, which would yield a very low cap number. Duke Energy does not believe this is the EPA’s intent, but given the lack of clarity in the Technical Support Document it is not possible to know with certainty what the EPA intends. Given the tremendous interest in understanding what the proposed rate-based goals might translate into on a mass basis, especially given the significant barriers to implementing the proposed program on a rate basis and the likelihood that many states may default to a mass-based approach, the EPA needs to do a much better job of communicating precisely how it is proposing the translation be performed. The EPA must also ensure that the regulatory language in any final guidelines is completely aligned with the approach the EPA envisions, or at least does not lock states into a single approach. 317 79 Fed. Reg. at 34,952, Proposed 40 C.F.R. §60.5770. 182 Any translation procedure must provide for the capturing of the emission reduction benefits of coal units retired after the baseline period. In other words, emissions from coal units that were in the baseline and factored into state goal calculations and are either actually retired after the baseline period or retired by a model being used to project emissions for the purpose of developing a mass caps, must be captured in the mass limits. Failing to include emissions from the coal units that were included in the baseline and state goal calculations but whose operation and emissions were not captured in the rate-to-mass translation procedure would mean that coal units retired after the baseline period would not contribute a single ton toward a state’s compliance under a mass-based approach. In other words, the procedure must reflect an assumption that all coal units included in the baseline are assumed to continue to operate when performing a rate-to-mass translation. The TSD318 issued by the EPA in November 2014 appears to be an attempt to address the rate-to-mass translation issue, but is less than helpful guidance regarding what the EPA might consider to be an acceptable rate-to-mass translation procedure. For example, it is unclear how the EPA’s reference to the calculation-based approaches described in the TSD as “illustrative” should be interpreted. The EPA fails to state that EPA would accept the described translation approaches and the resulting mass-based caps if states were to use them as the basis for establishing a mass-based plan. In addition, if states are not bound to use either of the described approaches to establish a mass-based plan, it is uncertain if the cap numbers that result from the illustrative calculations would be binding on a state. Additional guidance from EPA is necessary. Assuming that EPA would approve a conversion based on the illustrative calculations put forth in the TSD, it is unclear what happens if a state wants to develop a mass-based plan but 318 Translation of the Clean Power Plan Emission Rate-Based CO2 Goals to Mass-Based Equivalents, November 2014. 183 does not want to do so based on the use of the approaches described in the Agency’s November TSD, because they result in cap levels that are believed to be too stringent. The EPA fails to identify available options for states. Since the EPA omitted mention in the November 2014 TSD of the modeling-based translation approach it attempted to describe in the Projecting EGU CO2 Emission Performance in State Plan TSD, it is unclear if EPA is still considering such an approach as a viable option. If this original approach is no longer being considered by the EPA, a justification for this decision needs to be communicated to stakeholders. In short, the EPA needs to provide a much fuller discussion of the modeling approach or approaches it envisions that would allow states to adequately evaluate their use as an option for establishing a massbased plan. XIV. Using Gross vs. Net to Set Existing Source Requirements. The EPA states that the proposed regulation sets goals and monitoring and reporting requirements for EGUs based on net generation (net MWh) at the point of delivery to the transmission grid to afford the opportunity to meet the goals through efficiency improvements on auxiliary support equipment at the facility. The EPA believes that reporting based on net generation will pose little additional burden on EGUs because most facilities already have necessary equipment in place for measuring and reporting net generation. However, the EPA has solicited comment on whether the emissions goals for EGUs should be in the form of gross generation (gross MWh) to be consistent with monitoring and reporting requirements in the current 40 CFR 75 and with other output-based emissions standards for existing EGUs, as well as consistency with the EPA’s proposed gross output standard for new EGUs.319 319 79 Fed. Reg. at 34,894-34,895. 184 With respect to emissions goals based on gross versus net output, Duke Energy believes that any emissions goal for an EGU source that would be affected under a final section 111(d) program should be based on gross generation. Any emissions goal under Section 111(d) must be based on the BSER determination applicable to the affected source category. The affected source category under the EPA’s proposal is a fossil-fired electrical generating unit. Auxiliary support equipment at a power generating facility has consistently been regulated as separate source categories under section 111 and Part 60 requirements. For example, coal handling facilities are regulated under 40 CFR 60 Subpart Y. Auxiliary boilers are typically regulated under 40 CFR 60 Subpart Db or Dc, and are clearly distinct from the EGU. Non-emitting support systems, such as electric-powered water-intake structures and associated pumping or general facility HVAC systems, are not included in section 111 source definitions. Therefore, the emissions goals under the EPA’s proposed rule clearly should be based only on what is achievable at the affected source, which would be defined as emissions based on either fuel consumed by the actual emissions source or the gross output (gross MWh) from the emissions source. In addition, there are many factors that affect the auxiliary usage requirements at a given power plant. Those factors are dependent on many circumstances beyond the practical control of the operator, including geographical location, size of the facility and number of units, water availability, previous fundamental design choices for the auxiliary support and pollution control equipment, etc. Therefore, basing a goal for an affected source category in part on efficiencies that might be gained from auxiliary equipment introduces further inconsistency in how the emissions goal will affect each EGU. 185 Selecting a gross, versus net, basis affects the efficiency improvements that can be reliably achieved under Building Block 1. To the extent the EPA relied upon efficiency improvements to auxiliary equipment and non-emitting equipment to support its conclusion that a 6 percent average improvement in efficiency is achievable, the inclusion of auxiliary equipment is inappropriate. XV. Potential Reliability Impacts Compliance with the emission limits contained in the Proposed Guidelines has the potential to raise electric system reliability concerns associated with the shutdown of coal-fired generating units, which must be factored into any compliance schedule. The transmission system is planned and built to ensure reliable delivery of system resources to identified load centers, taking into account system contingencies, such as line and generation outages, as well as variation in the total system demand. When issues are identified, such as overloading of facilities, system voltages exceeding or falling outside acceptable limits, generating unit instability, or protective equipment inability to interrupt expected fault currents, projects are identified to correct the issue. All of the planning work is done in accordance with NERC planning standards. Generally speaking, transmission planning analysis focuses on a future horizon that allows sufficient lead time to complete corrective measures before the identified issues can occur. The corrective measures are chosen based on cost effectiveness; i.e., planning seeks to identify the most effective solution at the lowest cost, and lead times may vary from 1 to 2 years to several years depending on the type of corrective measure required. For example, replacement of a system component may take only a year, while construction of a new transmission line may take seven years or more. 186 When generating resources are affected by new environmental regulations, and compliance with those regulations affects continued operation of those resources, the approach to compliance needs to recognize that any resulting changes to generating resource operation, up to and including possible shutdown of that resource, will affect the pattern of system flows on the transmission system and potentially have a negative impact on transmission system reliability. While the transmission system is designed to accommodate generation outages, the shutdown of generation, and the replacement of that generation by another resource, possibly at a different location, is a significant variance from the assumptions under which the transmission system was designed and built. Significant changes to the pattern of power flows could result in cascading outages or voltage collapse under contingency conditions that were not considered in the original planning, if there is not sufficient time to implement corrective measures on the transmission system. Consider the following hypothetical example. If a generation resource must be retired due to environmental regulations within 3 years, and the power can be replaced through power purchases, but new transmission to facilitate the purchases or system reinforcements to support voltage in the retired generator’s local area will require 4 years to implement, the system will be exposed to serious outages for a period of about one year. Aside from the practical threat of outages, the utility would also be in violation of planning and operational standards for that period. The real impact to any specific system cannot be definitively answered without study of the very specific effects of proposed environmental regulation on the generation fleet. Assumptions cannot be generically made as to whether or not there will be a serious impact without completion of a transmission planning analysis based on the best estimate of generation 187 impacts, and it would be imprudent to establish a compliance deadline for the environmental regulation without consideration of the transmission reliability effects. The schedule EPA has laid out for implementation of its proposed emission guidelines, beginning in 2020, does not leave an adequate amount of time after states submit their implementation plans and the EPA approves those plans to allow development of a compliance strategy and identify and address any reliability issues that may result from the strategy. Failure to allow adequate time between a state’s SIP submittal and approval and the beginning of implementation to address any reliability issues could force the implementation of a less than optimal compliance strategy because the optimal strategy could not be implemented in the time provided due to related reliability problems. XVI. State Plans A. The EPA’s Proposal for Modifying a State Plans is Inappropriate and Must Be Revised. The EPA proposes that a state may revise an approved plan provided the revision does not result in reducing the required emission performance for affected EGUs specified in that state’s original approved plan.320 For the EPA to grant a modification request, the state must show that the revised set of measures would result in emission performance equal to or better than that of the original approved plan.321 In other words, the EPA is proposing to prohibit states from “backsliding” after the initial approval of a state plan – even if the revised state plan would still meet the state’s interim or final goals. Such a provision is not required by the CAA and the EPA cites no authority to support it. The only test that should be applied to a state plan modification is whether on the whole it meets 320 321 79 Fed. Reg. at 34,917. Id. 188 or exceeds a state’s goal; which is the minimum federal requirement. The provisions in a previously approved state plan that might be more stringent than a proposed plan modification must not disqualify the modification if the modified plan as a whole would meet or exceed the state’s goals. The number of highly uncertain variables that will need to be considered by the states as they develop plans to meet the requirements of the Proposed Guidelines years into the future is significant, and it is highly unlikely that a state would be able to get a plan “right” the first time.322 One could envision a situation where after several years of implementation, a state plan is shown to result in emissions that are far below where they were needed to be due to the fact that assumptions used in the development of the initial plan proved to be inaccurate or simply have changed with time, and the high level of plan performance is expected to continue into the future. Under such a scenario, it would be reasonable for the state to want to modify its plan to bring it more in line with the state’s goals and in the process lower the cost of compliance. Under the EPA’s proposal, however, the state would not be able to modify its plan to make it less stringent that its initial approved plan, and potentially less costly, even if the modified plan would still meet or exceed the state’s goal. This would inappropriately force higher compliance costs on the state than necessary. Meeting the state goals should be the only measure of plan acceptability. States must therefore have the flexibility to modify their approved plans, including the required emission performance for affected EGUs, in response to changing conditions, and have the performance of the modified plan judged solely against the state’s goal and not a previously approved state plan. This would not be backsliding because the state plan would still 322 Regulated utilities are required to prepare and submit IRPs as frequently as every year. Development of a state compliance plan would be more challenging than developing an IRP. It would be unreasonable to expect that a state would be able to develop a compliance plan that looks out many years and that plan would not need to be revised periodically to reflect changing conditions. 189 meet or exceed the goals set for the state. As proposed, EPA’s limit on a state’s ability to make such changes violates the cooperative federalism on the CAA and specifically violates Virginia v. EPA.323 B. States Should Have the Ability to Take Credit for Reduced or Avoid CO2 Emissions Occurring Starting from the End of the Base Period. The EPA has proposed that “. . . measures taken by a state or its sources after the date of this proposal, or programs already in place, and which result in CO2 emission reductions at affected EGUs during the 2020–2030 period, would apply toward achievement of the state’s CO2 goal.”324 The EPA goes on to request comment on using the start date of the initial plan performance period, the date of promulgation of the emission guidelines, the end date of the base period for the EPA’s BSER-based goals analysis, the end of 2005, or another date as possible alternatives to the use of the date of this proposal.325 Finally, the EPA solicits comment on an option that would recognize emission reductions that existing state requirements, programs and measures achieved starting from a specified date prior to the initial plan performance period, as well as emission reductions achieved during a plan performance period.326 Duke Energy recommends that measures taken by a state or its sources which result in reduced or avoided CO2 emissions at affected EGUs starting with the end of the base period used for the BSER-based goals analysis should apply toward achievement of the state’s CO2 goal. The use of this date would be consistent with the forward-looking approach the EPA has taken in establishing the state goals. This would include reduced or avoided emissions from RE and demand-side energy efficiency programs. Emission reductions realized after the end of the base 323 See Virginia v EPA, 108 F.3d 1397 (D.C. Cir. 1997). 79 Fed. Reg. at 34,892 - 34,893. 325 Id at 34,918. 326 Id. 324 190 period are real reductions, and Duke Energy sees no reason for states not to be able to recognize those reductions and apply them toward achievement of a state’s goal. Such emission reductions are not already included in state goal calculations, so there would be no risk of double-counting. Not allowing emission reductions from the end of the base period would unreasonably penalize states for acting early and discourage states from pursuing early action. Specifically with regard to demand-side energy efficiency measures, Duke Energy believes they should be treated the same way the EPA proposes to treat renewable energy. That is, like emission reductions from renewable energy requirements, programs and measures, the accomplishments from demand-side energy efficiency requirements, programs and measures that were in place prior to the end of the base period should be available to the states to apply toward achievement of their CO2 goal starting from the end of the base period. This is reasonable because the effects of end-use energy efficiency programs put in place prior to the proposed 2012 base year are reflected in the amount of generation and emissions from affected units in 2012 and are therefore factored into state goal calculations. There are a number of reasons why the EPA should allow states to use emission reductions achieved after the base period for compliance. The first is that such measures help to achieve the goal of the Proposed Guidelines, which is to reduce CO2 emissions from the electric power sector. Second, as the EPA recognizes, allowing states to count post-base period emission reductions would incentivize utilities and states to reduce their emissions earlier than they otherwise might. Without this provision, many stakeholders could be incentivized to wait to bring their RE facilities online or invest in demand-side energy efficiency measures, rather than investing in these emission reductions earlier. 191 While there would need to be a retrospective quantification of the CO2 emission reductions that occur prior to the finalization of program accounting requirements, Duke Energy does not think this would prove to be an insurmountable barrier. In its Notice of Data Availability (“NODA), the EPA notes that some stakeholders have suggested that “early reductions could be used as a way to ease the 2020-2029 glide path.”327 The NODA seeks comment on whether states could choose early implementation of state compliance plans, which would allow states to achieve the interim goals by making some reductions earlier.328 As noted above, allowing states to recognize early action that reduce emissions beginning at the end of the base period is an important tool that could be useful to states when designing compliance plans. As EPA notes, it is important to recognize early reductions so as not to create disincentives for pre-2020 reductions.329 Providing states with the flexibility to recognize emission reductions beginning from the end of the base period, however, would not eliminate the numerous problems posed by the proposed interim compliance period as detailed in section IV.B. of these comments, and does not alter Duke Energy’s recommendation that the proposed interim compliance period be eliminated in favor of allowing states to develop their own unique glide path to achieve their 2030 goals. Allowing states to take credit for early actions from the end of the base period, while a positive step, would not eliminate the reliability problems and stranded investments that would result from the proposed interim compliance period. The quantity of early credits that might be available to a state is far too uncertain to rely on as a “fix” for the many problems created by the interim compliance period. 327 79 Fed. Reg. at 64,545. Id. at 64,546. 329 Id. 328 192 C. States that Import Electricity Should Not Have to Discount EE Savings. The EPA proposes that a state only be allowed to include in its plan those CO2 emission reductions that occur in the state as a result of demand-side EE programs and measures implemented in that state.330 The EPA is concerned that in-state EE measures in states that import electricity would not result in the decreased utilization of in-state affected fossil-based units.331 For this reason, the EPA proposes that states would have to discount the CO2 emission reductions related to EE to reflect the level of electricity imports.332 The EPA’s approach to attributing EE savings assumes that a state could trace exactly which affected units generate less electricity as a result of increased EE. However, even the EPA recognizes that this is impossible, noting in the preamble that “some of the CO2 emissions avoided through RE and demand-side EE measures may be from non-affected EGUs.”333 The nature of the interconnected electric system makes it impossible to directly link certain EE measures with reduced utilization of specific units. Energy efficiency will reduce the amount of generation needed to satisfy customer demand, but neither EPA nor the states can determine exactly which units were utilized less as a result. Notwithstanding this, the EPA asks states to precisely assign “credit” for reductions associated with EE measures. Not only is this physically impossible, but it is conceptually at odds with EPA’s general approach to EE measures. As a general matter, the EPA is willing to accept a great deal of imprecision in determining the magnitude of reductions that result from EE 330 79 Fed. Reg. at 34,922. Id. 332 Id. 333 79 Fed. Reg. at 34,920. 331 193 measures.334 Similarly, the EPA includes EE in its definition of BSER, even though reductions are prospective and require rigorous EM&V protocols that, by definition, require states to make assumptions and to select between data sources—all of which adds uncertainty to the estimation of the emission reductions associated with EE programs.335 It would be arbitrary if the EPA allowed a general level of imprecision when calculating the benefits of EE, but then penalized states by requiring precise attribution of these estimated benefits for compliance purposes. Accordingly, the EPA should allow states to include the full estimated benefits of in-state EE programs in state plans, regardless of whether a state imports or exports electricity. Furthermore, it matters what type of generating facilities are producing the electricity that is imported into a state. For example, Duke Energy utility system covers most of North Carolina and a portion of South Carolina. North Carolina is a net importer of electricity, the vast majority of which is produced from Duke Energy’s 6 nuclear units in South Carolina (Duke Energy has no coal-fired EGUs in South Carolina and only has combustion turbines in addition to its nuclear units). While it may not be possible to identify with certainty the generating sources that would have reduced output as a result of EE programs, it is a certainty that EE programs in North Carolina are not reducing generation from Duke Energy’s nuclear units in South Carolina because the nuclear units are at the bottom of the dispatch stack due to their low operating cost. Energy efficiency will affect the marginal generating unit, which will be a fossil unit in North Carolina, not the lowest cost nuclear unit. Therefore, it is not appropriate for the EPA to require that North Carolina, for example, discount the CO2 emission reductions related to EE undertaken 334 335 Id. at 34,873. Id. at 34,920. 194 in the state based on the amount of electricity the state imports because EE programs in NC will not reduce the amount of electricity imported from nuclear plants in South Carolina. XVII. Inequities and Other Shortcomings in the Proposed Guidelines. A. The State Goal Computation Results in Inequitable Regulation of States and Affected EGUs. In calculating state goals, the EPA applied all four Building Blocks to each state’s 2012 electric generation to determine the extent to which the state could reduce its CO2 emissions rate by 2030.336 The EPA’s methodology in setting the goals is based on its conclusion that the four Building Blocks are part of an integrated “system” of operation of affected EGUs. However, the EPA has not taken the steps necessary to develop a technically sound BSER that demonstrates that the four Building Blocks are in fact integrated and achievable (setting aside the fact that a BSER that extends beyond the definition of the affected source is not legal). In fact, the EPA seems to acknowledge that individual states may find one or more of the Building Blocks technically infeasible or too costly to implement.337 The EPA’s analysis relies too heavily on modeling scenarios and assumptions rather than on the hard technical analysis required by the regulations in setting BSER, with the consequence that the EPA fails to address real concerns that individual states will face serious hurdles to implementing the Proposed Guidelines. The EPA simply concludes that there will not be a problem because the rule provides the states with 336 79 Fed. Reg. at 34,863. “Because the building blocks each establish a reasonable level of emission reduction rather than the maximum possible level of reduction, the EPA expects that, for any particular state, even if the application of the measures in one building block to that state would not produce the level of emission reductions reflected in the EPA’s quantification for that state, the state will be able to reasonably implement measures in other of the building blocks more stringently, so that the state would still be able to achieve the proposed goal.” 79 FR 34,893 This statement demonstrates that the EPA has not actually assessed whether its emissions guideline set for a given state is actually achievable, but that it simply assumes it has provided enough “reasonableness” so that the state can meet the proposed goals. 337 195 so much flexibility.338 For example, the EPA believes the proposal is justified because it believes the rule is imposing “reasonable” levels of each Building Block (“rather than the maximum”) and that a state should be able to increase its use of another Building Block, in such case, to compensate for a lower or no use of another Building Block.339 In fact, the EPA’s proposal is neither reasonable nor flexible, and will result in significant inequities among states. There are a number of issues which create these inequities that include inappropriate reliance on a single baseline year: unrealistic and flawed assessment of the capability of achieving heat rate improvement targets; renewable energy growth, and demand-side efficiency goals; failure to account for differences among the states across the nation; and failure to appropriately credit or account for efforts many EGU sources and states have already taken that have reduced the intensity of carbon emissions. A legally constructed section 111(d) rule would afford the required flexibility for each state to design its own rules that would achieve the objectives and guidelines established by the BSER for the affected source category and to hold its own sources accountable for compliance with source reduction targets that have been adequately demonstrated as achievable. Here, the EPA is proposing a course of action that will in essence force many states to enter into interstate compacts or trading programs or else turn over implementation of the rule to the EPA, not because they are exercising the flexibility afforded under section 111(d) but because the severity of the EPA’s required emissions reductions will require a level of control that is simply not feasible or technically achievable within those states. As such, the proposed rule is beyond the EPA’s authority under the CAA. 338 339 Id. at 34,893. Id. 196 As discussed previously in these comments, the proposed rule also will create inequity by forcing many EGU owners and operators to abandon or significantly curtail operation of generating units where significant investments have been made to install state-of-the-art control systems to meet MATS and other air regulations, including the Clean Air Interstate Rule,340 the Mercury and Air Toxics Standards,341 and in North Carolina, the North Carolina Clean Smokestacks Act.342 For regulated utilities, these costs are typically borne by customers in accordance with rates approved by state regulatory commissions. Where the EPA’s stringent and unjustified state emissions goals force retirement or significantly reduced utilization of these assets, the rule creates an inequity for consumers who must bear the costs related to these stranded investments and at the same time face significant cost increases through implementation of the Proposed Guidelines requirements. In fact, Duke Energy has already taken actions in North Carolina through upgrade of its coal-fired fleet, retirement of older generating units, and installation of new natural gas combined cycle facilities which not only reduced emissions of SO2, NOx, mercury, and other criteria or hazardous air pollutants, but also resulted in a 28 percent reduction in CO2 emissions from 2005 levels through 2013. But under the Proposed Guidelines, not only is there no credit for those actions, but North Carolina is punished for taking these actions by given a lower starting emission rate. And the citizens of North Carolina (and South Carolina to the extent impacted by ratemaking decisions) will now be subject to goals that are unduly strict and that are not equitable across the states. EPA has effectively created 50 subcategories of sources and tailor-made BSER by using each state’s emission rates as the starting point for the application of its Building Blocks. Never 340 70 Fed. Reg. at 25,162. 77 Fed. Reg. at 9,304. 342 SB 1078. 341 197 before has EPA taken this sort of approach to establishing any limit or guideline under section 111. EPA’s actions, which result in setting 50 different BSER limits for the same types of sources, is arbitrary and capricious. B. The Disparate Impacts of the Proposed Guidelines Across States Illustrate the Arbitrary and Capricious Nature of the Proposed Guidelines. Putting aside the fact that section 111(d) does not allow the establishment of state-level goals, the highly variable state goals proposed by the EPA result in some states facing a far more onerous burden to meet their goals than other states. This fact demonstrates not only the flaws in the Proposed Guidelines, but also the arbitrary and capricious nature of the Proposed Guidelines. Duke Energy will use five states in which it operates, North Carolina, South Carolina, Florida, Indiana, and Kentucky, to illustrate the inequitable and arbitrary and capricious nature of the Proposed Guidelines. The following table shows the 2012 fossil CO2 emission rates and the EPA’s proposed 2030 state goals for the five states.343 The table also shows the percentage change between each state’s 2012 fossil emission rates and their 2030 goal. State Florida Indiana Kentucky North Carolina South Carolina 2012 Fossil CO2 Emission Rate (lbs./MWh) 1,238 1,991 2,166 1,772 1,791 Proposed 2030 Goal (lbs./MWh) Percent Change From 2012 740 1,531 1,763 992 772 40% 23% 23% 44% 57% There is clearly no relationship between a state’s 2012 fossil emission rate and the amount by which each state would have to lower its CO2 emission rate based on the EPA’s proposed goals, other than perhaps an inverse relationship. Indiana and Kentucky, which have the highest 2012 CO2 emission rates of the five states, have the smallest reduction requirements 343 Goal Computation Technical Support Document, June 2014, 25-26. 198 of the five states. Requiring states with initially lower emission rates to make larger emission rate reductions relative to their base line rate makes no sense. The amount of existing and under construction NGCC capacity is a significant contributor to the high percentage reduction requirements for Florida and North Carolina. But rather than being rewarded, or at least not harmed for developing lower CO2 emitting NGCC generation, under the EPA’s Proposed Guidelines, Florida and North Carolina are being penalized for doing so. And under the EPA’s Proposed Guidelines, the more NGCC capacity that has been built in a state, the more that state gets penalized. North Carolina would have had less stringent goals had it not been so aggressive in replacing coal-fired generation with NGCC units, or at least had delayed the move from coal to gas by a couple of years. In addition, South Carolina is penalized for investing billions of dollars in over 2,000 MW of non-CO2 emitting new nuclear capacity with the largest CO2 emission rate reduction requirement. These outcomes defy logic. The following table shows the amount of each state’s 2012 coal-fired MWh generation that has been displaced by the Building Block 2 redispatch in the EPA’s state goal calculations. This clearly shows that the EPA’s Proposed Guidelines are significantly biased against states that have taken steps to build lower CO2 emitting NGCC units. State Florida Indiana Kentucky North Carolina South Carolina Percentage of 2012 Coal MWHs Displaced by Building Block 2 Redispatch 91% 5% 1% 33% 22% The results of the EPA’s IPM modeling of the Proposed Guidelines further confirm the inequitable and arbitrary impact of the Proposed Guidelines. The following table shows the 199 results of the EPA’s v5.13 Base Case and Option 1 Policy Case IPM modeling for Florida, Indiana, Kentucky, North Carolina, and South Carolina. MW of Coal-Fired Capacity in the EPA v5.13 Base Case and Option 1 Policy Case IPM Modeling State 2016 2018 2020 2025 2030 Florida – 8,869 8,869 8,869 8,869 8,869 Base Case Florida – 8,345 6,767 2,511 2,511 2,511 Policy Case Indiana – 16,106 16,106 16,106 15,523 13,523 Base Case Indiana – 15,706 15,706 15,706 15,706 13,123 Policy Case Kentucky – Base 11,175 11,175 11,175 11,175 11,175 Case Kentucky – 12,554 12,554 12,554 12,554 12,554 Policy Case North Carolina – 9,418 9,418 9,418 9,418 9,418 Base Case North Carolina – 7,267 6,780 6,780 6,780 6,780 Policy Case South Carolina – 4,924 4,924 4,924 4,924 4,924 Base Case South Carolina – 3,843 3,558 3,558 3,558 3,558 Policy Case Based on the EPA modeling, 72 percent of Florida’s coal-fired generating capacity that is in the Base Case is retired under the Policy Case. For North Carolina and South Carolina, 28 percent of each state’s Base Case coal-fired capacity is modeled to retire. Contrast this to Kentucky and Indiana. For Kentucky, the EPA modeling actually shows the amount of coalfired capacity increasing in the Policy Case relative to the Base Case344, and in Indiana, the EPA modeling shows less than 3 percent of the state’s Base Case coal-fired capacity retiring under the Policy Case. Again, the states that aggressively pursued NGCC and nuclear builds are the ones 344 What this shows is that the model is predicting fewer coal-fired EGU retirements under the Policy Case than the Base Case. 200 that are also shown to be the most impacted by the EPA’s Proposed Guidelines. These results seem counterintuitive, but not terribly surprising given the arbitrary and capricious nature of the EPA’s Proposed Guidelines in which it proposes to set different BSER limits for each state for the same types of sources. Finally, the modeled capacity factors of each state’s coal-fired EGUs further illustrate the inequitable impacts across states and the arbitrary and capricious nature of the Proposed Guidelines. The following table show the EPA modeled coal-fired EGU capacity factors for the Base Case and the Policy Case. Coal-Fired Capacity Factors in the EPA’s v5.13 Base Case and Policy Case IPM Modeling State 2016 2018 2020 2025 2030 Florida – 59% 67% 67% 73% 71% Base Case Florida – 67% 76% 14% 19% 32% Policy Case Indiana – 73% 78% 78% 80% 79% Base Case Indiana – 79% 80% 82% 78% 81% Policy Case Kentucky – 70% 77% 77% 79% 80% Base Case Kentucky – 76% 78% 83% 82% 83% Policy Case North Carolina – 67% 69% 69% 70% 69% Base Case North Carolina – 72% 69% 65% 62% 59% Policy Case South Carolina – 49% 48% 51% 58% 53% Base Case South Carolina – 57% 61% 50% 48% 48% Policy Case Consistent with the previous results, the above table shows that the modeled coal-fired EGU capacity factors in the Policy Case for Kentucky and Indiana are very similar to the Base Case capacity factors, but actually increase slightly relative to the Base Case by 2030. For North 201 Carolina and South Carolina, the modeled Policy Case capacity factors trend lower relative to the Base Case from 2020 to 2030. In Florida, however, the capacity factors in the Policy Case are modeled to drop by 80 percent in 2020 relative to the Base Case, to 14 percent. They are modeled to increase slightly by 2030, but are still shown to be 50 percent below the modeled 2030 Base Case capacity factor. At a 14 percent annual capacity factor, there is the question of whether any coal-fired EGU capacity would be kept in service at such a low a capacity factor. Building Blocks 3 and 4 have very different and inequitable effects on the fossil generation across the states due to their multiplier effect.345 What the multiplier effect means is that each MWh of non-emitting RE or demand-side energy efficiency allows a state to produce a certain number of MWh of fossil generation while still meeting its emission rate goal. The multiplier is determined by a state’s rate goal and its marginal fossil CO2 emission rate. The multiplier effect varies widely across the states, as shown in the following table. State 2030 Multiplier Effect 0.54 3.08 6.45 1.6 0.83 Florida Indiana Kentucky North Carolina South Carolina What the multiplier effect means is that every MWh of RE or energy efficiency in Kentucky allows 6.45 MWh of fossil generation in 2030. A MWh of RE or energy efficiency in Florida allows only 0.54 MWh of fossil generation in 2030. Another way of looking at it is that an additional 100 MWh of RE or energy efficiency above the Kentucky targets would allow an increase in fossil generation of 645 MWh, while the same excess 100 MWh of RE or energy efficiency in Florida would allow an increase in fossil generation of only 54 MWh, a nearly 12 345 See the comments filed by the Electric Power Research Institute (EPRI) for this rulemaking proceeding for a more detailed discussion of the multiplier effect, which the EPRI refers to as the Fossil leverage Factor. 202 fold difference. The multiplier effect therefore creates a significant cost inequity across the states, and there is no indication that the EPA considered this effect when developing the proposed Guidelines. In summary, the EPA’s Proposed Guidelines clearly would have inequitable impacts across states. Based on the EPA’s own modeling, the Proposed Guidelines would result in significant stranded investment in Florida, North Carolina, and South Carolina, while essentially leaving the coal-fired EGUs in Kentucky and Indiana virtually untouched, and the more a state has done to lower its CO2 emissions by developing NGCC and new nuclear generation, the more impacted they are by the Proposed Guidelines. This is further illustrated by the multiplier effect that values the same MWh of RE or energy efficiency very differently across states. It is important to note that Duke Energy is not presenting these data to suggest that the goals for Kentucky and Indiana should be made more stringent than those the EPA has proposed. We offer this analysis to illustrate the arbitrary and capricious nature of the Proposed Guidelines, and to support our belief that the Proposed Guidelines must be withdrawn. XVIII. The Proposed Guidelines Unlawfully Expands the EPA’s Authority, Obstructs States’ Flexibility in Developing Section 111(d) Programs, and Ignores the Obligation to Identify Appropriate Subcategories of Sources. A. The EPA’s Proposed Guidelines Exceed CAA Authority by Setting Mandatory Emissions “Guidelines” and Does Not Fulfill Its Duty to Evaluate Subcategories of Sources. Section 111(d) does not give the EPA direct regulatory authority over existing sources. Instead, section 111(d) directs the EPA to establish a “procedure” for states to submit plans establishing performance standards for existing sources. Section 111(d) gives the states broad discretion to develop such plans and to implement and enforce them based on specific state concerns and needs. The EPA recognized this in 1975 when it promulgated the Subpart B regulations to interpret and implement section 111(d): “States will have primary responsibility 203 for developing and enforcing control plans under section 111(d).”346 The EPA’s proposal to establish firm CO2 intensity caps infringes on that intent.347 The EPA may require states to submit plans that contain performance standards for emissions of certain pollutants from designated facilities, but it does not have the authority to dictate the form and content of those performance standards. Section 111(d)(2)(A) authorizes the EPA to set substantive standards of performance only in situations where a state has failed to submit an acceptable plan. Congress limited the EPA’s authority to establish substantive standards of performance for existing sources to those limited situations where a state fails to act. Thus, unlike the very different language in section 111(b) governing the standards of performance for new sources, section 111(d) gives the EPA no direct regulatory authority over existing sources, and instead gives states broad discretion to develop such plans subject to a general requirement that the state’s exercise of discretion be “satisfactory.”348 The CAA gives the states substantial freedom to determine the factors to be considered in formulating a state plan and how those factors are to be weighed, and it does not dictate any particular outcome for the state. States thus have significant discretion to adopt state plans that vary from the EPA’s emission guidelines. In the Proposed Guidelines, however, the EPA is imposing “binding” emission rates on each state.349 The EPA is proposing not to give states the flexibility to which they are entitled under the statute. Moreover, as discussed in greater detail elsewhere in these comments, the EPA would 346 40 Fed. Reg. 53,340, 53,343 (Nov. 17, 1975). 79 Fed. Reg. at 34,953; Proposed 40 C.F.R. § 60.5765, Table 1. 348 CAA § 111(d)(2)(A). 349 79 Fed. Reg. at 34,844, 34,892. 347 204 force states to violate the terms of the CAA by regulating sources that may not be regulated under a section 111(d) rule for existing fossil fuel-fired EGUs.350 Although the EPA asserts countless times in its Proposed Guidelines that it is giving states flexibility to adopt whatever “building blocks” it sees fit,351 in reality, because the standard of performance is an emission intensity cap applied to the state based on application of the four proposed building blocks rather than on what the affected facilities are capable of achieving, states in most cases will have little choice but to impose requirements on facilities that are not fossil fuel-fired EGUs in order to meet their EPA-mandated state-level emissions limits. In fact, in many states, it may be infeasible to adopt sufficient measures to achieve the EPA-mandated emissions limits, and therefore the EPA is in effect forcing such states either to go beyond their borders and enter into an emissions compact or trading program with other states or to tell the EPA it cannot meet the mandate and turn the program over to the EPA under the section 111(d)(2) provisions. While such steps may be within the flexibility section 111(d) provides to states, the EPA goes beyond its authority by imposing a broad new regulatory program that would require individual states to adhere to a federally mandated section 111(d) standard. In fact, despite the EPA’s claim to the contrary, it is clear that these proposed standards are set to meet a nationwide target, allocated among the states, rather than a general guideline based on the EPA’s evaluation of what sources can achieve at the state level. The EPA states that “This approach would mean that overall, the same nationwide level of emission 350 79 Fed. Reg. at 34,853 (“EPA is proposing that states be authorized to submit state plans that do not impose legal responsibility on the affected EGUs for the entirety of the emission performance level, but instead, by adopting what this preamble refers to as a ‘portfolio approach,’ impose requirements on other affected entities (e.g., renewable energy and demand-side energy efficiency measures) that would reduce CO 2 emissions from the affected EGUs.”). 351 Id. at 34,859 205 reductions as proposed would be achieved.”352 Nothing in section 111(d) requires or authorizes the EPA to achieve a nationwide level of emissions reductions. Section 111(d) does not allow the EPA to set a nationwide limit on emissions, but rather to set guidelines for states to consider when they adopt their own rules. It seems clear that the Proposed Guidelines are an attempt to set a national reduction target for CO2 emissions. As demonstrated by the numerous flaws inherent in EPA’s attempt to use the CAA to establish a utility sector CO2 reduction program, it is clear that Congressional action would be a more appropriate vehicle for establishing national climate policy. The emission guidelines and BSER determinations the EPA establishes are supposed to be largely procedural, and contain only nonbinding factors and descriptions of demonstrated systems of emission reductions for states to consider as the states set their own standards. They are not, as the EPA has proposed, supposed to be binding emission rate limitations on states. What the Agency determines to be BSER is merely one of the many factors states must consider in determining the level and form of any existing source performance standard as applied to a specific EGU. Similarly, under the Subpart B rules, states have considerable flexibility to deviate from the EPA’s emission guidelines in adopting plans and emission standards. For example, states may apply “less stringent emission standards or longer compliance schedules” to particular facilities or classes of facilities if the costs of adopting the standards suggested by the emission guidelines would be unreasonably costly, physically impossible, or for other reasons. 353 States have significant discretion in designing their own plans and determining how individual sources 352 353 Id. at 34,893. 40 C.F.R. § 60.24(f)(1)-(3). 206 or classes of sources may demonstrate compliance, including taking into account the “remaining useful life of the existing source.”354 In applying this criterion, states may grant individual sources or types of sources longer periods of time to comply, or may apply less stringent standards than set forth in the EPA’s emission guidelines. The Agency underscored as early as 1975 that “emission guidelines will reflect subcategorization within source categories where appropriate,” and the guidelines “will in effect be tailored to what is reasonably achievable by particular classes of existing sources . . . .”355 Because a standard of performance must be “adequately demonstrated” for each source, the EPA has an obligation in accordance with its Subpart B rules to establish highly subcategorized emission guidelines within a broad source category like existing fossil fuel-fired EGUs.356 The fact that the EPA has not done so may in fact reflect the reality that there is no appropriate standard of performance that can be set for existing sources. While Building Block 1 is based on achieving efficiency improvements at the affected sources, because the efficiency of an individual generating unit is to a large extent driven by the unit’s inherent design, there is little room for improvement and it is impossible to come up with a “standard” of performance for efficiency that could apply equally even within tight subcategories. Lacking any other feasible measures to control CO2 emissions, the EPA has instead turned to actions which fall entirely outside of the direct control of the affected sources, by its reliance on Building Blocks 2, 3 and 4 which are not a “system of control,” but a limitation on 354 CAA § 111(d)(1). 40 Fed. Reg. at 53,343. 356 40 C.F.R. § 60.22(b)(5). 355 207 the productive output of the regulated sources.357 Bringing non-affected sources into the proposed section 111(d) BSER determination and emissions guidelines is contrary to the EPA’s obligation to adopt measures that have been adequately demonstrated for the tightly defined subcategories of existing sources. Somehow, the EPA interprets the provisions in section 111(d) and Subpart B to actually go the opposite direction in categorizing the source – rather than addressing the significant differences among the wide range of EGU sources (as it has done in numerous other regulations) by establishing appropriate subcategories, the EPA is making an entirely new argument here that it can wash over the differences among affected EGUs by instead declaring a super-category which is “all of the affected EGUs in the State.”358 This reasoning essentially renders the Subpart B language meaningless where it directs the EPA to develop appropriate categories and subcategories. “The Administrator will specify different emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate.”359 Rather than address the differences between the affected EGU sources which would be subject to these requirements, the EPA has instead chosen to create a single broad category of “all sources within the state” and has ignored the fact that 357 The EPA determines that Building Blocks 2, 3 and 4 are feasible because a source “has the ability to limit its own operations.” The EPA also states that Building Blocks 2, 3 and 4 are equally valid under either its “primary” approach to BSER or the “alternative” approach because “building blocks 2, 3, and 4 would not be components of the system of emission reduction but instead would serve as bases for quantifying the reduced generation (and therefore emissions) at affected EGUs…” 40 FR 34,889. 358 “the EPA may apply the BSER to all of the affected EGUs in the state as a group. Similarly, the implementing regulations give the EPA broad discretion to identify the group of sources to which the BSER is applied. The regulations provide that the EPA ‘‘will specify different emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate.’’ Applying the BSER to the affected EGUs in each state as a group is appropriate, and therefore is consistent with these regulations.” EPA is saying here that after considering all of the differences among the sources in the EGU category, the answer is to “subcategorize” by grouping all of the facilities together in one state. 79 Fed. Reg. at 34,891. 359 (40 CFR 60.22(b)(5). 208 such broad categorization will in effect cause inequities among sources within the state which should have been addressed through the analysis of guidelines and compliance times applicable within appropriate subcategories. By its proposed actions, the EPA has completely eliminated the flexibility embedded in section 111(d). In the Proposed Guidelines, the EPA would set binding state emission reduction targets that cannot be adjusted by states once promulgated. The EPA’s aggressive assumptions in the building blocks further erode state flexibility and disregards the primacy that Congress explicitly gave to the states over the EPA under section 111(d). B. Consideration of a Facility’s “Remaining Useful Life” in Applying Standards of Performance. The EPA’s Proposed Guidelines include a discussion attempting to justify its proposed decision to significantly curtail state discretion to consider remaining useful life and other factors in developing a state plan and applying the EPA’s emission guideline.360 The EPA first asserts that deviating from its emission guideline based on remaining useful life or other factors is simply unnecessary given the flexibility the EPA has designed into its proposed emission guideline.361 The EPA argues instead that states can adjust requirements applicable to specific EGUs to accommodate their needs and make up for any adjustments to apply less stringent requirements to one EGU by making requirements for other EGUs (or other entities) more stringent. This argument assumes that there is enough room within each state’s goal to make such accommodations. The flexibility the EPA’s argument relies on, however, does not exist. Thus, as a practical matter, the EPA’s argument that deviation from its guidelines based on remaining useful life or other factors is unnecessary is incorrect. 360 361 79 Fed. Reg. at 34,925-26. Id. at 34,925. 209 The EPA’s argument also depends on its assertion that it has authority under the CAA to place limits on state consideration of remaining useful life. It does not. The EPA claims that although existing section 111(d) regulations allow for state consideration of remaining useful life and other factors and deviation from the EPA emission guidelines based on that consideration, the EPA is free to take that right away from the states.362 The source of state authority to consider remaining useful life in determining whether to adjust the EPA’s emission guideline is the CAA, not the EPA regulations. The CAA states: “Regulations of the Administrator under this paragraph shall permit the State in applying a standard of performance to any particular source under a plan submitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.”363 This language provides the EPA with no discretion to limit or prohibit states from taking remaining useful life and other factors into account in applying a standard of performance to individual sources. It is irrelevant if the EPA thinks this authority is unnecessary or if its rule might allow states an alternative that could approximate consideration of remaining useful life in some circumstances. The law clearly grants states this right. Finally, the EPA argues that it can alter the state’s authority to take remaining useful life into account and to deviate from or adjust the EPA’s emission guideline because the emission guideline the Agency has proposed differs so dramatically from the usual “presumptive standard of performance that must be fully and directly implemented by each individual existing source within a specified source category.”364 The fact that the EPA’s emission guideline deviates so 362 Id. (“EPA has discretion to alter the extent to which states may authorize relaxations to standards of performance that would otherwise apply to a particular source or source category”) 363 CAA § 111(d)(1)(B). 364 79 Fed. Reg. at 34,925. 210 significantly from other section 111(d) and CAA standards speaks to the validity of the emission guideline itself, and it does not give the EPA carte blanche to rewrite other provisions of the Act to better suit its desires. Duke Energy is encouraged that the EPA seems to have discovered that section 111(d)(1) requires that it “take into consideration, among other factors, the remaining useful life of the existing source to which [a] standard applies.” In its October 30, 2014 Notice of Data Availability, the EPA recognizes stakeholder concerns regarding stranded investment, suggests that “. . . an additional way to address these concerns may be for the Agency to take account of the book life of the original generation asset, as well as the book life of any major upgrades to the asset, such as major pollution control retrofits.”365 “The EPA requests comment on whether, and how, book life might be either used as part of the basis for the development of an alternative emission glide path for building block 2 or used to evaluate whether other ways of developing an alternative glide path (such as the phase-in approaches discussed above) would address stakeholders’ stranded investment concerns.”366 It is clear from the EPA’s discussion of this issue that it does not fully understand what book life is, and more importantly, what it is not. Book life is not an appropriate means of implementing the statutory mandate that it “take into consideration, among other factors, the remaining useful life of the existing source to which [a] standard applies.” Book life is an accounting and ratemaking concept that concerns asset depreciation. It does not describe the end of useful life of an asset, which should be determined on a case-by-case basis. The useful life of an electric generating asset extends well beyond an asset’s book life. 365 366 79 Fed. Reg. at 64,549. Id. 211 C. The EPA’s Four Building Blocks Take Away State Flexibility Rather Than Provide Flexibility The Proposed Guidelines lack flexibility because the state goals that are its centerpiece are set assuming significant emission reductions resulting from the application of all four Building Blocks. The EPA claims that states are free to disregard the policies represented by the Building Blocks when devising the elements of their plans. The EPA states: We also note that a state is not required to achieve the same level of emission reductions with respect to any one building block as assumed in the EPA’s BSER analysis. If a state prefers not to attempt to achieve the level of performance estimated by the EPA for a particular building block, it can compensate through over-achievement in another one, or employ other compliance approaches not factored into the state-specific goal at all. The EPA has estimated reasonable rather than maximum possible implementation levels for each building block in order to establish overall state goals that are achievable/while allowing states to take advantage of the flexibility to pursue some building blocks more aggressively, and others less aggressively, than is reflected in the goal computations, according to each state’s needs and preferences.367 The EPA claims that its “reasonable rather than maximum” approach to implementing the Building Blocks means that there is room for states to trade emission reductions among Building Block policies (and policies that were not included in the Building Blocks) to achieve each state’s goal. But the EPA’s Building Block assumptions used to set state goals are anything but reasonable. Accordingly, there is no true flexibility in the proposed emission guideline. Another reason the proposed emission guideline would limit rather than enhance flexibility for states is that it would encroach on areas that fall under the exclusive jurisdiction of the states. Most—if not all—of the programs in Building Blocks 2, 3, and 4 are the quintessential purview of state electricity regulators—not state environmental agencies. These programs have been developed pursuant to well-established state sovereign powers over matters relating to electricity regulation, including determining the appropriate mix of generating 367 79 Fed. Reg. at 34,926. 212 resources within a state. The EPA is barred by the Constitution and U.S. Supreme Court precedent from infringing upon a traditional state sovereign function unless Congress has adopted clear statutory language expressly authorizing the Agency to do so. Nothing in the CAA expressly authorizes the EPA to regulate the generation of electricity or other such energy regulatory matters traditionally reserved to states. Further, the EPA’s attempt to regulate electricity generation will adversely and inequitably harm the owners, investors and rate-paying customers of individual electric generating facilities by setting mandatory emissions guidelines which the EPA acknowledges are based primarily on regulating the production of electricity,368 not based on the technological ability to control CO2 emissions from the affected source category. The rule creates winners and losers within a state as well as among states, and the disparities are unrelated to the relative ability of a regulated facility to control its emissions. Such a program is clearly an expansion of the EPA’s authority, in addition to the inequity, since nothing in the CAA or the Subpart B rules contemplates such an expansive program of regulating the generation of electricity within a state’s borders or beyond. The Proposed Guideline acknowledges that interference with the sphere of exclusive state jurisdiction is a considerable concern: [I]ncluding [renewable energy (“RE”)] and demand-side [energy efficiency (“EE”)] measures in state plans would render those measures federally enforceable and thereby extend federal presence into areas that, to date, largely have been the exclusive preserve of the state and, in particular, state public utility commissions and the electric utility companies they regulate. 369 The EPA seeks comment on a proposal to remedy this situation by essentially creating a technical loophole. The EPA suggests that it can avoid entanglement in areas over which the 368 369 79 Fed. Reg. at 34,889. Id. at 34,902. 213 states are sovereign simply by not including things such as RE and EE in state plans, preventing such requirements from becoming federally enforceable, while states impose the requirements directly to allow compliance with what would be otherwise unachievable emission limits contained in state plans.370 This proposal mistakes formal federal enforceability with the problem of federal interference in areas that are exclusively the states’ domain. The EPA’s proposed solution, however, does not mitigate that problem. The same problem exists even if the EPA were to adopt only Building Blocks 1 and 2, because the rule sets emissions guidelines that can only be met by regulating how electricity production is managed within the state (or within a multi-state region if the state enters into such an agreement). Building Block 2 is not based on achieving CO2 emissions reduction but on requiring changes in how electricity is produced. The EPA also proposes what it calls the “state commitment approach.”371 This approach would not make requirements for non-EGUs part of a federally enforceable state plan: “Instead, the state plan would include an enforceable commitment by the state itself to implement stateenforceable (but not federally enforceable) measures that would achieve a specified portion of the required emission performance level on behalf of affected EGUs.”372 This approach clearly does not avoid the EPA’s interference in areas that are traditionally regulated only by the states. It merely seeks to avoid the appearance of such interference. But in attempting to do so, it also creates state plans that otherwise would not meet the requirement of federal enforceability. Therefore, Duke Energy’s response to the EPA’s request for comment is that Building Blocks 2, 3 and 4 are all outside the authority of what the EPA can do within section 111(d) and Subpart B, 370 Id. Id. 372 Id. 371 214 and those serious flaws cannot be remedied by the approaches the EPA has suggested to sidestep the legal requirements of the CAA. D. The Process and Timing for Submittal of State Plans Obstructs State Flexibility in Developing Plans The discussion of state plan submittal and approval processes in the Proposed Guidelines begins with an acknowledgement of the complexities posed by the section 111(d) Proposal and state concerns over the time it will take to develop a plan.373 The EPA therefore proposes to require plan submission by June 30, 2016, longer than the nine months allowed for under the existing section 111(d) rules.374 The EPA proposes that states may seek an additional year if they are entering into single-state plans, and they may seek an additional two years if they seek to join multi-state plans.375 But states cannot develop plans fundamentally reconfiguring the electric generation industry and power supply market in the short amount of time the EPA proposes to provide.376 Regulatory and legislative requirements in many states, including states where Duke Energy operates electric generating facilities, require greater than one year to formally adopt a rule from the time the rule has been crafted, and the EPA seems to recognize that problem by proposing a two-step approval process. But given the complexity of this rule, there will be numerous decisions, involvement of numerous governmental and non-governmental stakeholders, and conferences and high level meetings with regulatory bodies in other states before the state can even begin the process of drafting a rule. The tight deadline for adopting regulation obstructs the state’s authority to develop appropriate regulation of affected facilities because it short-changes the process and will force many states to adopt measures which are as 373 79 Fed. Reg. at 34,915. Id. 375 Id. 376 In fact, the EPA took even longer to develop its suite of section 111(b) and (d) GHG proposals, having issued its Advance Notice of Proposed Rulemaking in 2008; see 73 Fed. Reg. 44354, et seq. (July 30, 2008). 374 215 close as possible (within regulatory and legal constraints within the state) to the structure of the Proposed Guidelines (the four Building Block approach). Further, the EPA proposes to require states, in initial submissions, to justify any one-year or two-year deadline extension, and the Agency specifically asks for comments on whether there are justifications for extensions the EPA should reject.377 The EPA should take at face value states’ good faith efforts to attempt to comply with the EPA’s exceedingly complicated Proposed Guidelines, and accept any state assertion that more time is needed to develop a plan unless there is clear evidence to the contrary. In addition, the EPA proposes a number of required elements for initial plan submission, including a detailed roadmap to plan completion, before any deadline extension will be considered.378 Placing additional burdens on states already struggling to meet extended deadlines is a waste of resources. Moreover, the EPA should acknowledge that states have primary authority over plan contents and should defer to state judgments about what should properly be included in an initial plan submittal, consistent with section 111(d)’s requirement that states need only submit plans that are “satisfactory.” With respect to the Agency’s role in reviewing and approving state plans, the EPA requests comment on whether it should authorize itself to use the hybrid approval mechanisms it has developed under section 110 – the “partial approval and partial disapproval” and the “conditional approval.”379 Recognizing that disapprovals should be rare given the EPA’s limited review authority under section 111(d), the EPA should make use of its section 110 hybrid approval mechanisms where use of such mechanisms will assist the states in implementing the section 111(d) program. 377 Id. Id. at 34,915-916. 379 Id. at 34,916. 378 216 XIX. The EPA’s Calculation of the Costs of the Clean Power Plan Contains Errors That Results in a Substantial Underestimate of the Policy’s Cost Accompanying the EPA’s Proposed Guidelines is a Regulatory Impact Analysis (RIA) that fulfills the requirement under Executive Order 12866 for regulatory analysis assessing costs and benefits for all “economically significant” rulemakings of Executive Branch agencies.380 The RIA contains estimates of the benefits and costs of the regulation, their implications for net societal benefits, as well as information on other aspects of regulatory impact. Duke Energy retained NERA Economic Consulting to perform a detailed analysis of the EPA’s assessment of the costs of the Proposed Guidelines.381 As a result of this analysis, NERA identified substantial errors in the EPA’s calculations of the resulting compliance costs of the CPP. In particular, the EPA misstated the timing of energy efficiency and capital expenditures, resulting in a substantial understatement of both annual and present value compliance costs from 2016 through 2030. Using the EPA’s modeling, output files, and assumptions, NERA determined that correcting for the errors in the EPA calculation results in an increase in the policy cost over the period 2016 through 2030 from EPA’s $48 billion, to $224 billion (both in 2011$). The net present value costs increase from the EPA’s $32 billion to $182 billion (again in 2011$), almost a 6 fold increase. Having incorrect costs and incorrect timing of those costs call into question the EPA’s conclusions regarding their benefit-cost analysis in the RIA. XX. Conclusion In the above comments, Duke Energy devoted substantial pages to discussing the technical flaws in the four EPA Building Blocks. We noted that a 6 percent average heat rate 380 EPA, Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants. EPA-542/R-14-002, June 2014. 381 NERA’s report summarizing their analysis and findings is included as Attachment 1 to these comments. 217 improvement across coal-fired EGUs is unachievable even before consideration of the significant negative impact that building Blocks 2, 3, and 4 would have on heat rates due to the reduced capacity that existing coal-fired EGUs would experience. Duke Energy recommended that the EPA defer to the states to work with affected sources to determine appropriate unit-specific heat rate improvement targets. We noted that the EPA’s assessment of existing NGCC units which found that 10 percent of existing units operated at a 70 percent or greater capacity factor in 2012 fails to support the Agency’s finding that all existing NGCC units can therefore achieve an annual 70 percent capacity factor on an ongoing basis. Duke Energy identified several errors the Agency made in its interpretation and application of state RPS programs, including the programs in Ohio and North Carolina, and pointed out that the EPA’s proposed regional approach to setting state RE targets is fundamentally flawed and should be abandoned. Duke Energy pointed out the flaws in the EPA’s consideration of existing and under construction nuclear capacity and recommended that both be removed from state goal calculations. We also supported the EPA’s proposed treatment of existing hydro, new nuclear and nuclear uprates. We observed that the EPA’s overly simplistic and rather narrow analysis of state energy efficiency accomplishments fails to demonstrate the applicability or the feasibility of the 1.5 percent annual incremental energy efficiency savings rate the Agency used in setting each state’s energy efficiency targets. Duke Energy recommended that the EPA defer to the states to determine an appropriate level of energy efficiency for each state’s unique circumstances. Duke Energy recommended the elimination of the interim 2020-2029 compliance period due to the likelihood that it will cause electric reliability problems and a significant amount of stranded investment. In its place, we recommended that states should be allowed to determine their own glide path for achieving the 2030 targets, with no interim compliance obligations. Duke Energy pointed out numerous errors 218 the EPA made with the application of Building Block 2 that need to be corrected and the resulting adjusted states goals re-proposed for public comment. We noted that it is not appropriate to use any single year as a baseline for an electric sector program and recommended that the EPA use a baseline consisting of 2009 – 2012. We pointed out that new NGCC units cannot be considered a part of the EPA’s BSER determination and included in state goal calculations because they are regulated under section 111(b) and cannot simultaneously be regulated under section 111(d). We detailed the inequitable effects of the Proposed Guidelines across states and noted that the EPA significantly underestimated the cost of the Proposed Guideline because of errors it made in its calculations, which calls into question the EPA’s conclusions regarding their benefit-cost analysis. None of these comments offered by Duke Energy, however, should be taken as an endorsement of or support for any part of the Agency’s Proposed Guidelines. The EPA’s Proposed Guidelines first and foremost exceed the authority of the CAA and must be withdrawn. Simply tweaking various parts of the Proposed Guidelines will not change that fact. A complete overhaul is required, one that conforms to section 111(d) and its implementing regulations. A standard of performance under section 111 must be achievable by the individual regulated sources (coal-fired electric generating units (EGUs)) based on application of an “adequately demonstrated system of emission reductions” that a source owner can integrate into the design or operation of the source itself (“inside-the-fence”). The fundamental departure from the law in the EPA’s Proposed Guidelines is the Agency’s assertion that the “best system of emission reduction” (BSER) for coal-fired EGUs may include measures that would either directly or indirectly reduce a source’s utilization or that are not within the control of individual sources. A section 111 standard of performance cannot be based on “beyond-the-source” actions 219 like mandating the displacement of generation from coal-fired EGUs with generation from natural gas combined cycle (NGCC) units, displacing coal-fired generation with renewable energy, and decreasing electricity demand by increasing end-use energy efficiency. The EPA’s redefinition of what measures may constitute a “system of emission reduction” is contrary to over 40 years of the EPA’s consistent interpretation and implementation of section 111. In addition to being unlawful, The Proposed Guidelines are unconstitutional because they usurp sovereign state authority in violation of the Tenth Amendment. ATTACHMENTS 220 November 25, 2014 Comment on EPA’s Compliance Cost Estimate for the Clean Power Plan Authors: Scott Bloomberg and Anne Smith, NERA Economic Consulting In June 2014, the U.S. Environmental Protection Agency (EPA) released its Proposed Carbon Pollution Emissions Guidelines for Existing Power Plants, also called the “Clean Power Plan” (called the “CPP” hereafter).1 Accompanying this proposed rule is a Regulatory Impact Analysis (RIA) that is required under Executive Orders 12866 and 13563 for all major rulemakings of Executive Branch agencies.2 The RIA contains estimates of the benefits and costs of the regulation, their implications for net societal benefits, as well as information on other aspects of regulatory impact. Our detailed analysis of EPA’s assessment of the costs of the regulation has identified substantial errors in EPA’s calculations of the annual compliance costs of the CPP. In particular, EPA misstated the timing of energy efficiency, resulting in a substantial understatement of annual compliance costs in 2020, 2025, and 2030 (Figure 1).3 Figure 1: Comparison of Annual CPP Compliance Costs (Billions of 2011$) EPA (Annualized EE Costs) EPA (First-Year EE Costs) Annual Compliance Costs (Billions of 2011$) $30 $25 $20 $15 $10 $5 $0 2020 1 2025 2030 79 Federal Register 34830, June 18, 2014. 2 EPA, Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants. EPA-542/R-14-002, June 2014. 3 We focus on 2020, 2025, and 2030 because these are the years for which EPA presented compliance costs in its RIA (see Table ES-4). 1 November 25, 2014 In the following paragraphs we detail this error. Note that for purposes of this analysis, we do not modify any of EPA’s underlying cost estimates - all of our revised calculations are based upon the data that EPA has produced as part of the docket. 1. DERIVING THE EPA’S ANNUAL COMPLIANCE COSTS4 EPA’s annual compliance costs due to the CPP consist of two basic components: (1) costs related to changes in the costs of providing electricity services due to the CPP; and (2) costs related to the energy efficiency programs assumed under the CPP (which are assessed separately by EPA). The energy efficiency costs that EPA presents in the RIA are annualized values for 2020, 2025, and 2030. A. EPA’s Assessment of Electricity Services Costs The annual compliance costs related to the costs of providing electricity services that EPA presented in its RIA are derived from IPM Model outputs for a Base Case and selected scenarios,5 along with input assumptions from EPA’s Documentation for EPA Base Case v.5.13 Using the Integrated Planning Model,6 selected Technical Support Documents, and other assumptions as described below. The annual incremental costs associated with the CPP are from the EPA’s “SSR” IPM output files, which include a range of results for each model year (2016, 2018, 2020, 2025, 2030, 2040, and 2050). These outputs include “Total Annual Production Costs,” with the costs broken down between Variable O&M, Fixed O&M, Fuel, Capital, Pollutant Transport & Storage, and Total.7 EPA outputs for the Base Case and Option 1 – State are reproduced in Table 1 and Table 2. 4 NERA has prepared other reports that identify concerns regarding EPA’s cost and economic impact modeling assumptions and methodology, which are being submitted with other parties’ comments on the proposed CPP rule. This particular NERA report only addresses errors in EPA’s method of summarizing the timing of its cost estimates. The fact that this particular report does not identify or discuss other concerns with EPA’s cost input assumptions and modeling approach should not be viewed as an endorsement by us or other NERA staff of those aspects of EPA’s CPP cost estimates. 5 IPM Model Outputs are available at: http://www.epa.gov/airmarkets/powersectormodeling/cleanpowerplan.html. These costs are from the EPA Base Case for the proposed Clean Power Plan and Option 1- State. 6 IPM model documentation is available at: http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev513.html. 7 These data are included in Table 15 on the Table 1-16_US worksheet for the SSR file for both the Base Case and Option 1- State. 2 November 25, 2014 Table 1: Base Case Annual Production Costs from EPA Output File Base Case – April 2014 Draft 2016 2018 2020 2025 2030 15. Total Annual Production Cost [MMUS$](*) Variable O&M 13870 14334 14668 15427 15960 Fixed O&M 50617 52448 53261 56723 59347 Fuel 90035 95899 100214 115005 126656 Capital 4919 8228 9660 15772 22733 Pollutant Transport & Storage 0 0 -27 -27 -27 Total 159441 170908 177777 202901 224670 Sales Revenue 0 0 0 0 0 (*) Costs include only those items that are important for determining incremental cost of pollution control 2040 2050 18059 54116 164619 32504 -27 269270 0 20485 45188 239103 48501 -27 353250 0 2040 2050 14839 49193 126195 23291 -27 213492 0 17072 40151 188355 36471 -27 282023 0 Table 2: Option 1 – State Annual Production Costs from EPA Output File Option 1 State – April 2014 Draft 2016 2018 2020 2025 2030 15. Total Annual Production Cost [Million US2011$](*) Variable O&M 13747 13621 13330 13057 13001 Fixed O&M 48706 50302 50156 52687 54667 Fuel 90093 90213 94883 94873 101247 Capital 4696 10884 16694 18929 21807 Pollutant Transport & Storage 0 0 -27 -27 -27 Total 157242 165019 175036 179519 190695 Sales Revenue 0 0 0 0 0 (*) Costs include only those items that are important for determining incremental cost of pollution control Comparing the Total Annual Production Costs from the Base Case and Option 1 – State shows a net reduction in costs as shown in Table 3, but it is important to note that Total Annual Production Costs do not include any costs associated with energy efficiency. Table 3: Comparison of Total Annual Production Costs (Option 1 – State less Base Case, Millions of 2011$) Variable O&M Fixed O&M Fuel Capital Total B. 2016 2018 2020 2025 2030 2040 2050 (123) (1,911) 59 (224) (2,199) (713) (2,146) (5,686) 2,656 (5,889) (1,338) (3,105) (5,332) 7,033 (2,741) (2,370) (4,036) (20,132) 3,157 (23,382) (2,959) (4,680) (25,409) (926) (33,975) (3,220) (4,922) (38,423) (9,213) (55,779) (3,412) (5,037) (50,747) (12,031) (71,227) EPA’s Assessment of Energy Efficiency Costs EPA’s energy efficiency costs come from a Technical Support Document for GHG Abatement Measures.8 This Technical Support Document presents energy efficiency costs in two ways: 1) Annual first-year costs (including both the program and participant costs of the energy efficiency) and 2) Annualized total costs (also including both program and participant costs). 8 Available at: http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-ghg-abatement-measuresappendix5-4.xlsx. The relevant numbers are in the Opt 1 Costs @ 3% worksheet. 3 November 25, 2014 These costs are available for each year beginning in 2017 (not just years modeled in IPM), and are reproduced in Table 4.9 Table 4: Annual First-Year and Annualized Energy Efficiency Costs Table 4A. National level information on costs (2017 - 2050) Annual first-year costs (2011 $ M) Annual Annual totaltotal costcost of EE of EE Annual Annual program program costcost of EE of EE Annual Annual participant participant costcost of EE of EE Annualized total cost of EE (2011 $ M) Annualized Annualized totaltotal costcost of EE of EE Annualized Annualized program program costcost of EE of EE Annualized Annualized participant participant costcost of EE of EE 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 $14,728 $7,364 $7,364 $20,475 $10,238 $10,238 $26,054 $13,027 $13,027 $30,778 $15,389 $15,389 $34,706 $17,353 $17,353 $39,118 $19,559 $19,559 $41,990 $20,995 $20,995 $43,604 $21,802 $21,802 $43,750 $21,875 $21,875 $43,663 $21,832 $21,832 $43,615 $21,807 $21,807 $43,605 $21,803 $21,803 $43,634 $21,817 $21,817 $43,699 $21,850 $21,850 $1,743 $872 $872 $4,074 $2,037 $2,037 $6,938 $3,469 $3,469 $10,199 $5,100 $5,100 $13,733 $6,867 $6,867 $17,573 $8,787 $8,787 $21,509 $10,755 $10,755 $25,375 $12,688 $12,688 $28,986 $14,493 $14,493 $32,315 $16,157 $16,157 $35,366 $17,683 $17,683 $38,144 $19,072 $19,072 $40,654 $20,327 $20,327 $42,900 $21,450 $21,450 EPA’s illustrative compliance costs (Table ES-4 from the RIA and reproduced as Table 5) used Annualized total costs of energy efficiency. Table 5: Reproduction of Table ES-4 from RIA The total compliance costs that we have built up from EPA’s outputs for differences in electricity services costs (Table 3) and from EPA’s annualized total costs of energy efficiency (Table 4) are combined in Table 6. These numbers are within $0.1 billion of the reported costs from the RIA.10 9 The second panel of Table 4 includes energy efficiency costs that have been annualized (using a 3% discount rate), which are the costs that were used as part of EPA’s summary of compliance costs in Table ES-4 in the RIA. 10 It is not clear why these costs differ at all from those in the RIA since these are the back-up materials that EPA used for the costs presented in the RIA. 4 November 25, 2014 Table 6: EPA Compliance Costs Using Annualized Energy Efficiency Costs, Millions of 2011$) Difference in Total Annual Production Costs Annualized Cost of Energy Efficiency Total Compliance Costs 2. A. 2020 2025 2030 (2,741) 10,199 $7,458 (23,382) 28,986 $5,605 (33,975) 42,900 $8,925 CORRECTING EPA’S COST CALCULATIONS Correcting EPA’s Estimates of Energy Efficiency Expenditures While EPA chose to use the Annualized total costs of energy efficiency in its annual compliance costs, it is more appropriate to use the Annual first-year costs (including both the program and participant costs of the energy efficiency). These costs are also available for each year beginning in 2017, and are also included in Table 4.11 Instead of using the Annual first-year costs for energy efficiency, EPA used Annualized total costs of energy efficiency (also shown in Table 4). This use of the Annualized costs instead of the Annual first-year costs has the impact of pushing energy efficiency costs out into the future (undiscounted first-year costs in Table 4 for 2017 through 2030 are $513 billion, while undiscounted annualized energy efficiency costs are $320 billion, or nearly $200 billion lower). Pushing the costs out into the future also results in making the compliance costs for 2020, 2025, and 2030 that EPA presents in the RIA appear lower than they are (even while still using only EPA’s results). Adding the proper Annual first-year energy efficiency costs to the difference in total annual production costs (Table 3) results in the total compliance costs for the CPP. The total compliance costs using Annual first-year energy efficiency costs for 2020, 2025, and 2030 are $28 billion, $20 billion, and $10 billion, respectively (Table 7). Table 7: Corrected Compliance Costs, Option 1 – State, Millions of 2011$) Difference in Total Annual Production Costs Annual First-Year Cost of Energy Efficiency Total Compliance Costs 2020 2025 2030 (2,741) 30,778 $28,037 (23,382) 43,750 $20,369 (33,975) 43,699 $9,725 These compliance costs, calculated entirely from EPA model inputs and outputs, are significantly higher than the compliance costs that EPA has reported in the RIA, which are $7.4 billion, $5.5 billion, and $8.8 billion in 2020, 2025, and 2030, respectively (also reproduced as Table 5) 11 The first panel of Table 4 includes energy efficiency costs that represent Annual first-year costs of energy efficiency. 5 November 25, 2014 The only difference between the compliance costs in Table 7 and EPA’s from Table ES-4 (Table 5) is the treatment of energy efficiency costs. In EPA’s presentation of compliance costs, they used annualized energy efficiency costs instead of first-year costs as shown in Table 6. The differences in annual compliance costs using the two treatments of energy efficiency costs lead to the question as to which approach is more correct. EPA’s approach to addressing energy efficiency costs in retail electricity rates provides some guidance. From the RIA: The utility funding for demand-side energy efficiency programs (to cover program costs) is typically collected through a standard per kWh surcharge to the ratepayer; the regional retail price impacts analyzed from this RIA’s compliance scenarios assumes the recovery of these program costs through the following procedure. For each state, the first-year EE program costs are calculated for each year (which are equal to 50% of the total first-year EE costs for that state as noted above).12 Thus, for purposes of calculating retail electricity rates, EPA has opted to use first-year energy efficiency costs, yet they are then inconsistent in using annualized energy efficiency costs when presenting total compliance costs. This does not make any logical sense because energy efficiency costs are incurred and paid for immediately – the spending is not spread out over time, nor is the recovery of the costs spread out. Thus, it is clear that a more appropriate way to measure energy efficiency costs is to use the Annual first-year costs as we have done. EPA’s incorrect treatment of energy efficiency costs leads to a very large understatement of the total annual compliance costs in various years (more than $20 billion and almost $15 billion understatements in 2020 and 2025, respectively). Correcting EPA’s error in the costs in Table 5 (and Table 6) shows the true cost of the EPA’s CPP is significantly higher than EPA has claimed in its RIA. 12 EPA, Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants. EPA-542/R-14-002, June 2014, p. 3-18, emphasis added. 6