*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review ***

EO 12866_111(b) New-Mods 2060-AQ91 Final_20150507 6560-50 -P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 60, 70, 71, and 98 [EPA-HQ-OAR-2013-0495; EPA-HQ-OAR-2013-0603; FRL- XXXX-XX9930-66 - OAR] RIN 2060-AQ91 Standards of Performance for Greenhouse Gas Emissio ns from New, Modified, and Reconstructed Stationary Sources: Ele ctric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: The Environmental Protection Agency (EPA) is finali zing new source performance standards (NSPS) under Clean Air Act (CAA) section 111(b) that, for the first time, will establish standards for emissions of carbon dioxide (CO 2 ) for newly constructed, modified, and reconstructed affected f ossil fuelfired electric utility generating units . (EGUs). This action establishes separate standards of performance for f ossil fuelfired electric utility steam generating units and f ossil fuelfired stationary combustion turbines. This action a lso addresses related permitting and reporting issues. In a separ ate action, under CAA section 111(d), the EPA is issuing final emission guidelines for states to use in developing plans to limit CO 2 emissions from existing fossil fuel-fired EGUs.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 2 of 854

DATES: This final rule is effective on [ insert date 60 days after date of publication in the federal registerFederal Register ]. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of [ insert date of publication in the Federal Register ].

ADDRESSES: The EPA has established dockets for this action un der Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Pe rformance for Greenhouse Gas Emissions from New Stationary Source s: Electric Utility Generating Units) and Docket ID No. EPA-HQ- OAR-2013-0603 (Carbon Pollution Standards for Modified and Recons tructed Stationary Sources: Electric Utility Generating Uni ts). All documents in the dockets are listed on the www.regu lations.gov Web site. Although listed in the index, some inform ation is not publicly available, e.g., Confidential Business Inf ormation or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted materia l, will be publicly available only in hard copy. Publicly avai lable docket materials are available either electronically in www.regulations.gov or in hard copy at the EPA Dock et Center (EPA/DC), Room 3334, EPA WJC West Building, 1301 Co nstitution Ave. NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excl uding legal holidays. The telephone number for the Public Readi ng Room is*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 3 of 854 (202) 566-1744, and the telephone number for the Ai r Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Divi sion (D243- 01), U.S. EPA, Research Triangle Park, NC 27711; te lephone number (919) 541-2968, facsimile number (919) 541-5 450; email address: hutson.nick@epa.gov or Mr. Christian Felln er, Energy Strategies Group, Sector Policies and Programs Divi sion (D243- 01), U.S. EPA, Research Triangle Park, NC 27711; te lephone number (919) 541-4003, facsimile number (919) 541-5 450; email address: fellner.christian@epa.gov.

SUPPLEMENTARY INFORMATION: Acronyms. A number of acronyms and chemical symbols are used in this preamble. While t his may not be an exhaustive list, to ease the reading of this preamble and for reference purposes, the following terms and acr onyms are defined as follows: AB Assembly Bill AEO Annual Energy Outlook AEP American Electric Power ANSI American National Standards Institute ASME American Society of Mechanical Engineers ASTM American Society for Testing of Materials BACT Best Available Control Technology BDT Best Demonstrated Technology BSER Best System of Emission Reduction Btu/kWh British Thermal Units per Kilowatt-hour Btu/lb British Thermal Units per Pound CAA Clean Air Act CAIR Clean Air Interstate Rule CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration)*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 4 of 854 CDX Central Data Exchange CEDRI Compliance and Emissions Data Reporting Inter face CEMS Continuous Emissions Monitoring System CFB Circulating Fluidized Bed CH 4 Methane CHP Combined Heat and Power CO 2 Carbon Dioxide CSAPR Cross-State Air Pollution Rule DOE Department of Energy DOT Department of Transportation ECMPS Emissions Collection and Monitoring Plan Syst em EERS Energy Efficiency Resource Standards EGU Electric Generating Unit EIA Energy Information Administration EO Executive Order EOR Enhanced Oil Recovery EPA Environmental Protection Agency FB Fluidized Bed FGD Flue Gas Desulfurization FOAK First-of-a-kind FR Federal Register GHG Greenhouse Gas GHGRP Greenhouse Gas Reporting Program GPM Gallons per Minute GS Geologic Sequestration GW Gigawatts H 2 Hydrogen Gas HAP Hazardous Air Pollutant HFC Hydrofluorocarbon HRSG Heat Recovery Steam Generator IGCC Integrated Gasification Combined Cycle IPCC Intergovernmental Panel on Climate Change IPM Integrated Planning Model IRPs Integrated Resource Plans kg/MWh Kilogram per Megawatt-hour kJ/kg Kilojoules per Kilogram kWh Kilowatt-hour lb CO 2 /MMBtu Pounds of CO 2 per Million British Thermal Unit lb CO 2 /MWh Pounds of CO 2 per Megawatt-hour lb CO 2 /yr Pounds of CO 2 per Year lb/lb-mole Pounds per Pound-Mole LCOE Levelized Cost of Electricity MATS Mercury and Air Toxic Standards MMBtu/hr Million British Thermal Units per Hour MRV Monitoring, Reporting, and Verification MW Megawatt MWe Megawatt Electrical*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 5 of 854 MWh Megawatt-hour MWh-g Megawatt-hour gross MWh-n Megawatt-hour net N 2 O Nitrous Oxide NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification Syste m NAS National Academy of Sciences NETL National Energy Technology Laboratory NGCC Natural Gas Combined Cycle NOAK n th -of-a-kind NRC National Research Council NSPS New Source Performance Standards NSR New Source Review NTTAA National Technology Transfer and Advancement Act O 2 Oxygen Gas OMB Office of Management and Budget PC Pulverized Coal PFC Perfluorocarbon PM Particulate Matter PM 2.5 Fine Particulate Matter PRA Paperwork Reduction Act PSD Prevention of Significant Deterioration PUC Public Utilities Commission RCRA Resource Conservation and Recovery Act RFA Regulatory Flexibility Act RGGI Regional Greenhouse Gas Initiative RIA Regulatory Impact Analysis RPS Renewable Portfolio Standard RTC Response to Comments RTP Response to Petitions SBA Small Business Administration SCC Social Cost of Carbon SCR Selective Catalytic Reduction SCPC Supercritical Pulverized Coal SDWA Safe Drinking Water Act SF 6 Sulfur Hexafluoride SIP State Implementation Plan SNCR Selective Non-Catalytic Reduction SO 2 Sulfur Dioxide SSM Startup, Shutdown, and Malfunction Tg Teragram (one trillion (10 12 ) grams) Tpy Tons per Year TSD Technical Support Document TTN Technology Transfer Network UIC Underground Injection Control UMRA Unfunded Mandates Reform Act of 1995 U.S. United States*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 6 of 854 USDW Underground Source of Drinking Water USGCRP U.S. Global Change Research Program VCS Voluntary Consensus Standard WGS Water Gas Shift WWW World Wide Web Organization of This Document. The information pres ented in this preamble is organized as follows: I. General Information A. Executive Summary B. Does this action apply to me? C. Where can I get a copy of this document? D. Judicial Review E. How is this preamble organized? II. Background A. Climate Change Impacts from GHG Emissions B. GHG Emissions from Fossil Fuel-fired EGUs C. The Utility Power Sector D. Statutory Background E. Regulatory Background F. Development of Carbon Pollution Standards for Fossil FuelFiredfired Electric Utility Generating Units G. Stakeholder Engagement and Public Comments on the P roposals III. Regulatory Authority, Affected SourcesEGUs and Their Standards, and Legal Requirements A. Authority to Regulate Carbon Dioxide from Fossil Fu el-fired EGUs B. Treatment of Categories and Codification in the Cod e of Federal Regulations C. Affected Units D. Units Not Covered by Thisthis Final Rule E. Coal Refuse F. Format of the Output- Basedbased Standard G. CO 2 Emissions Only H. Legal Requirements for Establishing Emission Standa rds I. Severability J. Certain Projects under Development IV. Summary of Final Standards for Newly Constructed, M odified, and Reconstructed Fossil Fuel-fired Electric Utilit y Steam Generating Units A. Applicability Requirements and Rationale B. Best System of Emission Reduction C. Final Standards of Performance V. Rationale for Final Standards for Newly Construc ted Fossil Fuel-fired Electric Utility Steam Generating Units*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 7 of 854

A. Factors Considered in Determining the BSER B. Highly Efficient SCPC EGU Implementing Partial CCS as the BSER for Newly Constructed Steam Generating Units C. Rationale for the Final Emission Standards D. Post-Combustion CCSCarbon Capture E. Pre-Combustion CCSCarbon Capture F. Vendor Guarantees, Industry Statements, Academic Li terature, and Commercial Availability G. Response to Key Comments on the Adequacy of the Technical Feasibility Demonstration H. Consideration of Costs I. Key Comments Regarding the EPA’s Consideration of Costs J. Achievability of the Final Standards K. Achievable Emission Reductions Utilizing Partial CCS L. Further Development and Deployment of CCS Technolog y M. GeologicTechnical and Geographic ConsiderationsAspects of Disposition of Captured CO 2 N. Final Requirements for Disposition of Captured CO 2 O. Non-air Quality Impacts and Energy Requirements O.P. Options That Were Considered by the EPA but Were Ultimately Not Determined to Be the BSER Q. Summary VI. Rationale for Final Standards for Modified Foss il Fuel-fired Electric Utility Steam Generating Units A. Rationale for Final Applicability Criteria for Modi fied Steam Generating Units B. Identification of the Best System of Emission Reduc tion C. BSER Criteria VII. Rationale for Final Standards for Reconstructe d Fossil Fuel-fired Electric Utility Steam Generating Units A. Rationale for Final Applicability Criteria for Reco nstructed Sources B. Identification of the Best System of Emission Reduc tion VIII. Summary of Final Standards for Newly Construc ted , Modified, and Reconstructed Stationary Combustion Turbines A. Applicability Requirements B. Best System of Emission Reduction C. Final Emission Standards D. Significant Differences between Proposed and Final Combustion Turbine Provisions IX. Rationale for Final Standards for Newly Constru cted , Modified, and Reconstructed Stationary Combustion Turbines A. Applicability B. Subcategories B.C. Identification of the Best System of Emission Reduc tion C.D. Achievability of the Final Standards X. Summary of Other Final Requirements for Newly Co nstructed,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 8 of 854 Modified, and Reconstructed Fossil Fuel-fired Electric Utility Steam Generating Units and Stationary Combustion Tu rbines A. Startup, Shutdown, and Malfunction Requirements B. Continuous Monitoring Requirements C. Emissions Performance Testing Requirements D. Continuous Compliance Requirements E. Notification, Recordkeeping, and Reporting Requirem ents XI. Consistency between BSER Determinations for This Ru le and the Rule for Existing EGUs A. Newly Constructed Steam Generating Units B. New Combustion Turbines C. Modified and Reconstructed Steam and NGCC Units XII. Interactions with Other EPA Programs and Rules A. Overview B. Applicability of Tailoring Rule Thresholds under the PSD Program C. Implications for BACT Determinations under PSD D. Implications for Title V Program E. Implications for Title V Fee Requirements for GH Gs F. Interactions with Other EPA Rules XIIXIII . Impacts of this Action A. What are the air impacts? B. Endangered Species Act C. What are the energy impacts? D. What are the water and solid waste impacts? E. What are the compliance costs? F. What are the economic and employment impacts? G. What are the benefits of the final standards? XIIIXIV . Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Revi ew and Executive Order 13563: Improving Regulation and Reg ulatory Review B. Paperwork Reduction Act (PRA) C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act (UMRA) E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordinatio n with Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulatio ns that Significantly Affect Energy Supply, Distribution, o r Use I. National Technology Transfer and Advancement Act (N TTAA) and 1 CFR part 51 J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and L ow-Income Populations*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 9 of 854

K. Congressional Review Act (CRA) XIVXV. Withdrawal of Proposed Standards for Certain Modified Sources XVI . Statutory Authority I. General Information A. Executive Summary 1. Purpose of the Regulatory Action ThisIn this final action finalizes regulatory requirements tothe EPA is establishing standards that limit greenhouse gas (GHG) emissions from newly constructed, modified, a nd reconstructed fossil fuel-fired electric utility st eam generating units and stationary combustion turbines , following the issuance of proposals for such standards and an accompanying Notice of Data Availability. On June 25, 2013, in conjunction with the announcem ent of his Climate Action Plan (CAP), President Obama issu ed a Presidential Memorandum directing the EPA to issue a proposal to address carbon pollution from new power plants by S eptember 30, 2013, and to issue “standards, regulations, or guid elines, as appropriate, which address carbon pollution from mo dified, reconstructed, and existing power plants.” Pursuant to authority in section 111(b) of the CAA, on September 20, 2013 , EPA Administrator Gina McCarthy signedthe EPA issued proposed carbon pollution standards for newly constructed fossil fu el-fired power plants. The proposal was published in the Federal Register*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 10 of 854 on January 8, 2014 (79 FR 1430; “January 2014 propo sal”). 1 In that proposal, the EPA proposed to limit emissions of CO 2 from newly constructed fossil fuel-fired electric utilit y steam generating units and newly constructed natural gas- fired stationary combustion turbines. The EPA subsequently issued a Notice of Data Availa bility (NODA) in which the EPA solicited comment on its in itial interpretation of provisions in the Energy Policy A ct of 2005 (EPAct05) and associated provisions in the Internal Revenue Code (IRC) and also solicited comment on a companion Tec hnical Support Document (TSD) that addressed these provisi ons’ relationship to the factual record supporting the p roposed rule. 79 FR 10750 (February 26, 2014). On June 2, 2014, Administrator McCarthy signedthe EPA proposed standards of performance, also pursuant to CAA section 111(b), to limit emissions of CO 2 from modified and reconstructed fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines. 7 9 FR 3495934960 (June 18, 2014) (“June 2014 proposal”). Specifical ly, the EPA proposed standards of performance for: (1) modified

1 The EPA previously proposed performance standards for newly reconstructed fossil fuel-fired EGUs in April 2012 (77 FR 22392). In that action, the EPA proposed standards for steam generating units and natural gas-fired combustion t urbines based on a single Best System of Emission Reduction deter mination. On January 8, 2014, the EPA withdrew that proposal (79 FR 1352).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 11 of 854 fossil fuel-fired steam generating units, (2) modif ied natural gas-fired stationary combustion turbines, (3) recon structed fossil fuel-fired steam generating units, and (4) r econstructed natural gas-fired stationary combustion turbines. In this action, the EPA is issuing final standards of performance to limit emissions of greenhouse gas ( GHG ) pollution manifested as CO 2 from newly constructed, modified, and reconstructed fossil fuel-fired electric utility st eam generating units (i.e., utility boilers and integrated gasification combined cycle (IGCC) units) and from newly

constructed , modified, and reconstructed stationary combustion turbines. Consistent with the requirements of CAA s ection 111(b), these standards reflect the degree of emiss ion limitation achievable through the application of th e best system of emission reduction (BSER) that the EPA has deter mined has been adequately demonstrated for each type of unit. These final standards are codified in 40 CFR part 60, subpart T TTT, a new subpart specifically created for CAA 111(b) standar ds of performance for GHG emissions from fossil fuel-fired EGUs

. In a separate action that affects the same source c ategory, under CAA section 111(d), the EPA is issuing final emission guidelines under CAA section 111(d) for states to use in developing plans to limit CO 2 emissions from existing fossil fuel-fired EGUs. StatesPursuant to those guidelines, states must*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 12 of 854

then submit plans to the EPA following a schedule set b y the guidelines. The EPA received numerous comments and conducted ex tensive outreach to stakeholders for this rulemaking. After careful consideration of public comments and input from a v ariety of stakeholders, the final standards of performance in this action

reflect somecertain changes from the proposals. Comments considered include written comments that were submi tted during the public comment period and oral testimony provid ed during the public hearing for the proposed standards. 2. Summary of Major Provisions and Changes to the P roposed

Standards The BSER determinations and final standards of per formance for affected newly constructed, modified, and recon structed EGUs are summarized in Table 1 and discussed in more det ail below. The final standards for new, modified, and reconstr ucted EGUs apply to sources that commenced construction – or m odification or reconstruction, as appropriate – on or after the date of publication of corresponding proposed standards. 2 The final standards for newly constructed fossil fuel-fired E GUs apply to those sources that commenced construction on or aft er the date of publication of the proposed standards, January 8 , 2014. The

2 See CAA section 111(a)(2).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 13 of 854 final standards for modified and reconstructed foss il fuel-fired EGUs apply to those sources that modify or reconstr uct on or after the date of publication of the proposed stand ards, June 18, 2014. Table 1. Summary of BSER and Final Standards for Af fected SourcesEGUs Affected SourceEGUs BSER StandardFinal Standard s of Performance

Newly ConstructedFossil FuelFired Steam Generating Units PartialEfficient new supercritical pulverized coal (SCPC) utility boiler implementing partial carbon capture and storage (CCS) 1,400 lb CO 2 /MWh- grossg .

Modified Fossil Fuel-Fired Steam Generating Units Most efficient generation at the affected sourceEGU achievable through a combination of best operating practices and equipment upgrades Sources making modifications resulting in an increase in potential CO 2 hourly emissions of more than 10 percent are required to meet a unit-specific emission limit determined by the unit’s best historical annual CO 2 emission rate (from 2002 to the date of the modification); the emission limit will be no lowermore stringent than: 1. 1,800 lb CO 2 /MWhgrossg for sources*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 14 of 854 with heat input > 2,000 MMBtu/h. OR 2. 2,000 lb CO 2 /MWhgrossg for sources with heat input ≤ 2,000 MMBtu/h.

ReconstructedFossil FuelFired Steam Generating Units Most efficient generating technology at the affected source (supercritical steam conditions for the larger; and subcritical conditions for the smaller) 1. Sources with heat input > 2,000 MMBtu/h are required to meet an emission limit of 1,800 lb CO 2 /MWhgrossg . 2. Sources with heat input ≤ 2,000 MMBtu/h are required to meet an emission limit of 2,000 lb CO 2 /MWhgrossg .

Newly Constructed , Modified, and ReconstructedFossil FuelFired Stationary Combustion Turbines Efficient NGCC technology for baseload natural gasfired units and clean fuels for non-base load and multi-fuel-fired units 3 1. 1,000 lb CO 2 /MWhgrossg or 1, 080030 lb CO 2 /MWhnetn for base load natural gas-fired units. 2. 120 lb CO 2 /MMBtu for non-base load natural gas-fired units. 2.3. 120 to 160 lb CO 2 /MMBtu for multifuel-fired units. 4

3 The term "multi-fuel-fired" refers to a stationary combustion turbine that is physically connected to a natural g as pipeline, but that burns a fuel other than natural gas for 10 percent or more of the unit's heat input capacity during the 1 2-operatingmonth compliance period. 4 The emission standard for combustion turbines co-f iring natural gas with other fuels shall be determined at the end of each operating month based on the amount of co-fired nat ural gas. Units only burning natural gas with other fuels wit h a relatively consistent chemical composition and an e mission*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 15 of 854

a. Fossil fuel-fired electric utility steam generat ing units

. This action finalizesestablishes standards of performance for newly constructed fossil fuel-fired steam gener ating units 5

based on the performance of a new highly efficient SCPC EGU implementing post-combustion partial carbon capture and storage (CCS) technology, which the EPA determines to be the BSER for these sources. After consideration of thea wide range of comments, technical input received on the availabil ity, technical feasibility, and cost of CCS implementati on, and publicly available information about projects that are implementing or planning to implement CCS, the EPA remains convincedconfirms its proposed determination that CCS technology is available and technically feasible to implement at fossil fuel-fired steam generating units. However, the EPA ’s final

standard does recognize thatreflects the proposed standards should be adjusted to addressconsideration of legitimate

factor of 160 lb CO 2 /MMBtu or less (e.g., natural gas, distillate oil, etc.) only need to maintain records of the fue ls burned at the unit to demonstrate compliance. Units burning f uels with variable chemical composition or with an emission f actor greater than 160 lb CO 2 /MMBtu (e.g., residual oil) must conduct periodic fuel sampling and testing to determine the overall CO 2 emission rate. 5 Also referred to as just “steam generating units” or as “utility boilers and IGCC units”. These are units t hat are covered under 40 CFR part 60, subpart Da for criter ia pollutants.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 16 of 854 concerns regarding the cost to implement the available CCS technology on a new steam generating unit. Accordin gly, the EPA is finalizing an emission standard for newly constr ucted fossil fuel-fired steam generating units at 1,400 lb CO 2 /MWh- grossg , a level that is less stringent than the proposed limi tation (which

was atof 1,100 lb CO 2 /MWh- gross).g. This final standard reflects our identification of the BSER for such units to be a lower level of partial CCS than waswe identified as the basis of the proposed standards – one that we conclude better re presents the requirement that the BSER technology be implementable at

reasonable costscost . The EPA proposed and reaffirms here that the BSER for newly constructed steam generating EGUs was highly effici ent new generating technology (i.e., a supercritical utilit y boiler or IGCC unit) implementing partial CCS technology to a chieve CO 2 emission reductions resulting in an emission limit of 1,100 lb

CO 2 /MWh-g. 6 The BSER for newly constructed steam generating EGU s in the final rule is very similar to that in the January 2 014 proposal.

In this systemfinal action, the EPA finds that a highly efficient new supercritical pulverized coal (SCPC) utility

6 Using the most recent data on partial capture rate s to meet an emission standard of 1,100 lb CO 2 /MWh-gross, about 35 percent capture would be required at an SCPC unit and about 22 percent capture would be required at an IGCC unit.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 17 of 854 boiler EGU implementing partial CCS to the degree n ecessary to achieve an emission of 1,400 lb CO 2 /MWh-g is the BSER. Contrary to the January 2014 proposal, the EPA finds that IG CC technology – either with natural gas co-firing or implementing partial CCS – is not part of the BSER, but recognizes that IGCC technology can serve as an alternative method of compliance. The EPA finds that a highly efficient SCPC implemen ting partial CCS is the BSER because CCS technology has been demonstrated to be technically feasible and is in u se or under construction in various industrial sectors , including the power generation sector . For example, the Boundary Dam Unit #3 CCS project in Saskatchewan, Canada is a full-scale, fu lly integrated CCS project that is currently operating and is designed to capture more than 90 percent of the CO 2 from the lignite-fired boiler. In addition, partial CCS designed to meet the final emission standard will promote implementa tion and further development of CCS technologies. A newly constructed conventional coal-fired, highly efficient SCPC utility boiler burning bituminous coal will be able to meet this final standard of performance by capturing and storing approximate ly 2016 percent of the CO 2 produced from the facility. Many IGCC unitsA newly constructed, highly efficient SCPC utility bo iler burning*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 18 of 854 subbituminous coal or dried lignite 7 will be able to meet thethis final standard of performance by capturing and stor ing less than 10approximately 23 percent of the CO 2 produced byfrom the facility. AllAs an alternative compliance option, utilities a nd project developers will also be able to construct n ew steam generating sources may also be able tounits (both utility boilers and IGCC units) that meet the final standard through alternative actions, such as the use of performance by co-firing with natural gas co-firing . This final standard of performance for newly constructed fossil fuel-fired steam gener ating units provides a clear and achievable path forward for th e construction of new coal-fired generatingsuch sources that addresses greenhouse gaswhile addressing GHG emissions and supportssupporting technological innovation. The standard of 1,400 lb CO 2 /MWh- grossg is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide r ange of conditions, and throughout the United States. We note that identifying a highly efficient new SCPC EGU implementing partial CCS as the BSER can provideprovides a path

7 For a summary of lignite drying technologies, see “Technoeconomics of modern pre-drying technologies forlignite-fired power plants” available at www.ieacoal.org.uk/documents/83436/9095/Techno-economics-o f-modern-predrying-technologies-for-lignite-fired-power-plants, -CCC/241; “Drying the lignite prior to combustion in the boil er is thus an effective way to increase the thermal efficiencies and reduce the CO 2 emissions from lignite-fired power plants.”*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 19 of 854

forward for new fossil fuel-fired steam generation in the current market context. Numerous studies have foundpredicted that few new fossil - fuel - fired steam generating units will be constructed in the future for multiple reasons. These analyses identify a range of factors unrelated to this rulem aking , including low electricity demand growth, highly com petitive natural gas prices, and increases in the supply of renewable energy. The EPA recognizes that , in certain circumstances , there may be interest in building fossil fuel-fired steam generating units despite these market conditions : in. In particular, utilities and project developers may build new foss il fuel-fired steam generating EGUs in order to achieve or maintain fuel diversity within generating fleets and, as a hedge against the possibility of natural gas prices far exceeding pro jections , or

to generateco-produce both power and chemicals, including capturing CO 2 for use in enhanced oil recovery (EOR) projects. 8

8 As the EIA has stated: Policy-related factors, such as environmental regulations and investment or production tax credit s for specified generation sources, can also impact investment decisions. Finally, although levelized c ost calculations are generally made using an assumed se t of capital and operating costs, the inherent uncertainty about future fuel prices and future policies may cause plant owners or investors who finance plants to place a value on portfolio diversification . While EIA considers many of these factors in its analysis of technology choice in the*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 20 of 854 As regulatory history has shown, identifying a new highly efficient SCPC EGU implementing partial CCS as the BSER in this

rule willis likely to further boost research and developmentsdevelopment in this technologyCCS technologies , making its applicationthe implementation even more efficacious and cost-effective – and, while providing a competitive, low emission future for fossil fuel-fired steam generation. The EPA is also issuing final standards for steam generating units that implement “large modification s ”,,” (i.e., modifications resulting in an increase in potential hourly CO 2 emissions of more than 10 percent when compared to the source’s potentialhighest hourly emissions in the previous 5 years). 9 The EPA is not issuing final standards, at this time, for steam generating units that implement “small modification s” (i.e., modifications resulting in an increase in potential hourly CO 2 emissions of less than or equal to 10 percent when compared to

electricity sector, these concepts are not included in LCOE or LACE calculations. http://www.eia.gov/forecasts/aeo/electricity_genera tion.cfm

9 40 CFR 60.14(h) – “No physical change, or change i n the method of operation, at an existing electric utility steam generating unit shall be treated as a modification for the pur poses of this section provided that such change does not increase the maximum hourly emissions of any pollutant regulated under t his section above the maximum hourly emissions achievable at th at unit during the 5 years prior to the change.”*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 21 of 854

the source’s potentialhighest hourly emissions in the previous 5 years). The standards of performance for the modified steam generating units that make large modifications are based on each affected unit’s own best potential performance as t he BSER. Specifically, such a modified steam generating unit will be required to meet a unit-specific CO 2 emission limit determined by that unit's best demonstrated historical performanc e (in the years from 2002 to the time of the modification). 10 The EPA has determined that this standard based on each unit’s own best potential performance can be met through a combinat ion of best operating practices and equipment upgrades and that these steps can be implemented cost-effectively at athe time when a source is undertaking a large modification. To account for facilities that have already implemented best practices and eq uipment upgrades, the final rule also specifies that modifi ed facilities will not have to meet an emission standard more str ingent than the corresponding standard for reconstructed steam generating units (i.e., 1,800 lb CO 2 /MWh- grossg for units with heat input greater than 2,000 MMBtu/h and 2,000 lb CO 2 /MWh- grossg for units with heat input less than or equal to 2,000 MMBtu/h ).

10 For the 2002 reporting year the EPA introduced new automated checks in the software that integrated automated qu ality assurance (QA) checks on the hourly data. Thus, the EPA believes that the data from 2002 and forward are of higher q uality.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 22 of 854 The final standards for steam generating units impl ementing large modifications are similar to the proposed sta ndards for such units. In the proposal, we suggested that the standard should be based on when the modification is underta ken (i.e., before being subject to requirements under a CAA se ction 111(d) state plan or after being subject to such a plan). We also suggested that for units that undertake modificatio ns prior to becoming subject to an approved CAA section 111(d) state plan, the standard should be its best historical performa nce plus an additional two percent reduction. In response to co mments on the proposal, we are not finalizing separate standards that are dependent upon when the modification takes place, n or are we finalizing the proposed additional two percentage r eduction. The EPA is not promulgating final standards of perf ormance for, and is withdrawing the proposed standards for , modified steam generating sources that make modifications re sulting in an potential increase of hourly CO 2 emissions of less than or equal to 10 percent . (see Section XV of this preamble). As we indicated in the proposal, the EPA has been notifie d of very few modifications for criteria pollutant emissions from the power sector to which NSPS requirements have applied. As such, we expect that there will be few NSPS modifications for GHG emissions as well. Even so, we also recognize (and we discuss in this preamble) that the power sector is undergoing significant*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 23 of 854 change and realignment in response to a variety of influences and incentives in the industry. We do not have suff icient information at this time, however, to anticipate th e types of modifications , if any, that may result from these changes. In particular, we do not have sufficient information a bout the types of modifications , if any, that would result in increases in CO 2 emissions of 10 percent or less, and what the appr opriate standard for such sources would be. Therefore, we c onclude that it is prudent to delay issuing standards for source s that undertake small modifications (i.e., those resultin g in an increase in CO 2 emissions of less than or equal to 10 percent). For reconstructed steam generating units, the EPA is finalizing standards of performance based on the performance of the most efficient generating technology for these types of units as the BSER (i.e., reconstructing the boiler if necessary to use steam with higher temperature and pressure, even if the boiler was not originally designed to do so .)). 11 The emission standard for these sources is 1,800 lb CO 2 /MWh- grossg for large sources, (i.e. those with a heat input rating of gr eater than 2,000 MMBtu/h) or 2,000 lb CO 2 /MWh- grossg for small sources (i.e .., those with a heat input rating of 2,000 MMBtu/h or

11 Steam with higher temperature and pressure has mor e thermal energy that can be more efficiently converted to el ectrical energy.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 24 of 854 less). The difference in the standards for larger a nd smaller units is based on greater availability of higher pressure/temperature steam turbines (e.g., supercri tical steam turbines) for larger units. The standards can also be met through other non-BSER technology options , such as natural gas co-firing. b. Stationary combustion turbines

. This action also finalizes standards of performance for newly constructed , modified, and reconstructed stationary combustion turbines. The In the January 2014 proposal for newly constructed EGUs, the EPA originally proposed that newly constructed, modified, or reconstructednatural gas- fired stationary combustion turbines (i.e., turbines combusting over 90 percent natural gas) would be subject to a standard of performance for CO 2 emissions if they are constructed for the purpose of supplying and actually sellannually supply to the grid (1) one-third or more of their potential electric outp ut 12

and (2) more than 219,000 MWh , 13 based on a three-year rolling average. We refer to units that operate above the grid. Later, inelectric sales thresholds as "base load units," a nd we refer

12 We refer to thresholds related to an EGU's actual annual electrical sales (as a fraction of potential annual output) as "percentage electric sales criteria." 13 We refer to thresholds related to an EGU's actual annual electrical sales in megawatt-hours as "total electr ic sales criteria."*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 25 of 854 to units that operate below these thresholds as "no n-base load units." In the January 2014 proposal for newly constructed combustion turbines, the EPA proposed standards for two subcategories of base load natural gas-fired statio nary combustion turbines. The proposed standard for smal l combustion turbines (units with base load ratings less than or equal to 850 MMBtu/h) was 1,100 lb CO 2 /MWh-g. The proposed standard for large combustion turbines (units with base load ratings g reater than 850 MMBtu/h) was 1,000 lb CO 2 /MWh-g. The EPA did not propose standards for non-base load units.

In the June 2014 proposal for modified and reconstruc ted sourcescombustion turbines , the EPA solicited comment on alternative approaches for establishing applicability and subcategorization criteria , including (1) eliminating the “constructed for the purpose of supplying” qualifie r for the total electric sales and percentage electric sales criteria, (2) eliminating the 219,000 MWh total electric sales criterion , the constructed for the purpose of criterion, and altog ether, (3) replacing the one-third fixed percentage electric sales criterion with a variable percentage electric sales criterion with an approach that would allow net-electric sale s up to the design efficiency of the combustion turbine being i nstalled multiplied by its potential electric output before a standard*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 26 of 854 would apply.(i.e., the sliding-scale approach 14 ), and (4) eliminating the proposed small and large subcategor ies for base load natural gas-fired combustion turbines. These proposed applicability requirements were intended to exclude combustion turbines that are used for the purpose of meeting p eak power

demand (i.e., “peaking units”), as opposed to those that are

used to meet intermediate or base load power demand. In both proposals, the EPA also solicited comment o n a broad applicability approach that would include non -base load natural gas-fired units (primarily simple cycle com bustion turbines) and multi-fuel-fired units (primarily dis tillate oilfired combustion turbines) in the general applicabi lity of subpart TTTT. As part of the broad applicability ap proach, the EPA solicited comment on imposing “no emission stan dard” or establishing separate numerical limits for these tw o subcategories. In this action, the EPA is finalizing a variation o f the two approaches put forward in the June 2014 proposa l. For newly constructed, modified, orapproaches put forward in the January 2014 proposal for new sources and the June 2014 pro posal for modified and reconstructed sources. Based on our re view of

14 The sliding-scale approach determines a unit-speci fic percentage electric sales threshold equivalent to a unit’s net design efficiency (the maximum value is capped at 5 0 percent).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 27 of 854 public comments related to the proposed subcategori es for small and large combustion turbines and our additional da ta analyses, we have determined that there is no need to set two separate standards for different size combustion turbines fo r base load natural gas-fired combustion turbines. The EPA has determined that all sizes of affected newly constructed and reconstructed stationary combustion turbines can achieve the final standards. For newly constructed and reconstructed base load n atural gasfired stationary combustion turbines, the EPA is finalizing a standard of 1,000 lb CO 2 /MWh- grossg based on modern, efficient natural gas combined cycled (NGCC) technology as th e BSER. However, the final applicability excludes units subjectAlternatively, owners and operators of base load natural gas-fired combustion turbines may elect to comply with a federally enforceable permit that restrict annual s tandard based

on net - output of 1,030 lb CO 2 /MWh-n. The EPA is eliminating the 219,000 MWh total annual electric sales to the design net efficiency of criterion for non-CHP units. In addition, the EPA is finalizing the slidingscale approach for deriving the unit-specific, perc entage electric sales threshold above which a combustion turbine (not to exceed 40 percent) multiplied by the potential e lectric output of transitions from the combustion turbinesubcategory for non-base load units to the subcategory for base loa d units . For*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 28 of 854 example, a stationary combustion turbine with a des ign net efficiency of 38 percent (on a higher heating value (HHV) basis) would be able to request a permit restriction to al low it to sell up to 38 percent of its potential electric out put without becoming subject to this final standard. 15 newly constructed and reconstructed non-base load natural gas-fired stati onary combustion turbines, the EPA is finalizing the comb ustion of clean fuels (natural gas with a small allowance for distillate oil) as the BSER with a corresponding heat input-ba sed standard of 120 lb CO 2 /MMBtu. This standard of performance will apply to the vast majority of simple cycle combustion turbin es. The EPA is finalizing a heat input-based clean fuels standa rd because we have insufficient information at this time to set a uniform output-based standard that can be achieved by all n ew and reconstructed non-base load units. The EPA previously proposed to divide intermediate and base load stationary combustion turbines into two subcat egories based on their size (as determined by heat input rating) and to set separate standards of performance for each of those

15 A turbine with a HHV design net efficiency of 45 p ercent would be allowed to sell up to 40 percent of its potentia l electric output before it would be subject to this final sta ndard. A stationary combustion turbine with a HHV design net efficiency of 30 percent would be allowed to sell up to 30 per cent of its potential electric output before it would be subjec t to this final standard.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 29 of 854 subcategories. Based on our review of the comments on the proposed subcategories and standards and additional data analysis, however, we have determined that there is no need to set separate standards for different sizes of combu stion turbines. The EPA has determined that all sizes of affected newly constructed, modified, and reconstructed stat ionary combustion turbines will be able to achieve the fin al standard. Stationary combustion turbines that are physically incapable of combusting natural gas, such as turbin es in certain non-continental locations or in remote locations th at lack access to a natural gas pipeline, will be exempt fr om the standard entirely. In addition, for newly constructed and reconstructe d multifuel-fired stationary combustion turbines, the EPA is finalizing an input-based standard of 120 to 160 lb CO 2 /MMBtu based on the combustion of clean fuels as the BSER. 16 The EPA has similarly determined that it has insufficient information at this time to set a uniform output-based standard for stationary combustion turbines that operate with significant quantities o f a fuel other than natural gas.

16 Combustion turbines co-firing natural gas with oth er fuels shall determine fuel-based site-specific standards at the end of each operating month. The site-specific standards d epend on the amount of co-fired natural gas.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 30 of 854 We are not promulgating final standards of performa nce for stationary combustion turbines that make modificati ons at this time. We are simultaneously withdrawing the propose d standards for modifications (see Section XV of this preamble) . As we indicated in the proposal, sources from the power s ector have notified the EPA of very few NSPS modifications, an d we expect that there will be few NSPS modifications for CO 2 emissions as well. Moreover, our decision to eliminate the subca tegories for small and large EGUs and set a single standard of 1 ,000 lb

CO 2 /MWh-g has raised questions as to whether smaller e xisting combustion turbines that undertake a modification c an meet this standard. As a result, we have concluded that it is prudent to delay issuing standards for sources that undertake modifications until we can gather more information. A more detailed discussion of the final standards o f performance for stationary combustion turbines , the applicability criteria, and the comments that influ enced the final standards is provided in Sections VIII and IX of this preamble. 3. Costs and Benefits As explained in the regulatory impact analysis (RI A) for this final rule, available data – including utility announcements and Energy Information Administration (EIA) modeling - indicate that, even in the absence of th is rule, (i)*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 31 of 854 existing and anticipated economic conditions are su ch that few, if any, fossil fuel-fired steam-generating EGUs wil l be built in the foreseeable future, and (ii) utilities and proj ect developers are expected to choose new generation te chnologies (primarily NGCC) that would meet the final standard s and renewable generating sources that are not affected by these final standards. These projections are consistent w ith utility announcements and EIA modeling that indicate that n ew units are

more likely to be NGCC and that any coal-fired steam gen erating units built between now and 20202030 would have CCS, even in the absence of this rule. 17 Therefore, based on the analysis presented in Chapter 4 of the RIA, the EPA projects that this final rule will result in negligible CO 2 emission changes, quantified benefits, and costs by 2022 as a result of the performance standards for newly constructed EGUs. 18 However, as noted earlier, for a variety of reasons , some companies may consider coal-fired steam generating units that the modeling does not anticipate. Thus, in Chapter 5 of the RIA, we also

17 The EPA’s Integrated Planning Model (IPM) projects no new noncompliant coal (i.e., newly constructed coal-fired plants that do not meet the final standard of performance) thro ughout the model horizon of 2030 (there is a small amount of n ew coal with CCS that is hardwired into the modelling, consisten t with EIA assumptions to represent units already under constr uction or under development). 18 Conditions in the analysis year of 2022 are repres ented by a model year of 2020.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 32 of 854 present an analysis of the project-level costs of a newly constructed coal-fired steam generating unit with p artial CCS that meets the requirements of this final rule alon gside the project-level costs of a newly constructed coal-fir ed unit without CCS. This analysis indicates that the quantified benefits of the standards of performance would exce ed their costs under a range of assumptions. As explained in the RIA for this final rule and further below, the EPA has been notified of few power secto r NSPS modifications or reconstructions ; and, based. Based on that experience, the EPA expects that few EGUs will trig ger either the modification or the reconstruction provisions t hat we are finalizing in this action. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the cost s and benefits of the standards for modified and reconstr ucted

sources. B. Does this action apply to me? The entities potentially affected by the standards are shown in Table 2 below. Table 2. Potentially Affected Entities a

Category NAICS

Code Examples of Potentially Affected Entities*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 33 of 854

Industry 221112 Fossil fuel electric power generating units.

Federal Government 221112 b Fossil fuel electric power generating units owned by the federal government.

State/Local Government 221112 b Fossil fuel electric power generating units owned by municipalities.

Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.

a Includes NAICS categories for source categories th at own and operate electric power generating units (including boilers and stationary combined cycle combustion turbines). b Federal, state, or local government-owned and oper ated establishments are classified according to the acti vity in which they are engaged.

This table is not intended to be exhaustive , but rather to provide a guide for readers regarding entities like ly to be affected by this action. To determine whether your facility, company, business, organization, etc., would be reg ulated by this action, refer to Section III of this preamble for more information and examine the applicability criteria in 40 CFR 60.1 (General Provisions) and 40 CFR 60.550840 of s ubpart TTTT (Standards of Performance for Greenhouse Gas Emissi ons for*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 34 of 854 Electric Utility Generating Units). If you have any questions regarding the applicability of this action to a par ticular entity, consult either the air permitting authority for the entity or your EPA regional representative as liste d in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions). C. Where can I get a copy of this document? In addition to being available in the docket, an electronic copy of this final action will also be available on the Worldwide Web (WWW). Following signature, a copy of this final action will be posted at the following address: http://www2.epa.gov/carbon-pollution-standards. D. Judicial Review Under section 307(b)(1) of the CAA, judicial r eview of this final rule is available only by filing a petition f or review in the U.S. Court of Appeals for the District of Colum bia Circuit by [ insert date 60 days after publication in federal register ]. Under section 307(d)(7)(B) of the CAA, only an obje ction to this final rule that was raised with reasonable specific ity during the period for public comment can be raised during judicial review. the Federal Register ]. Moreover, under section 307(b)(2) of the CAA, the requirements established by this fi nal rule may not be challenged separately in any civil or crimin al proceedings brought by the EPA to enforce these requirements. Section 307(d)(7)(B) of the CAA further provides th at “[o]nly an*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 35 of 854 objection to a rule or procedure which was raised w ith reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for usmandating

the EPA to convene a proceeding for reconsideration , “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [t he period for public comment] or if the grounds for such objectio n arose after the period for public comment (but within the time specified for judicial review) and if such objection is of centra l relevance to the outcome of the rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washing ton, DC 20460, with a copy to both the person(s) listed in the preceding

FOR FURTHER INFORMATION CONTACT section, and the Associate General Counsel for the Air and Radiation Law Offic e, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 P ennsylvania Ave., NW, Washington, DC 20460. E. How is this preamble organized? This action presents the EPA’s final standards of performance for newly constructed, modified, and re constructed fossil fuel-fired electric utility steam generating units and natural gas-firednewly constructed and reconstructe d stationary*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 36 of 854 combustion turbines. Section II provides background information on climate change impacts from GHG emissions, GHG e missions from fossil fuel-fired EGUs, the utility power sector, t he statutory and regulatory background relating to CAA section 1 11(b), EPA actions prior to this final action, and public comm ents regarding the proposed actions. Section III explain s the

EPAEPA’s authority to regulate CO 2 and EGUs, identifies affected

sourcesEGUs , and describes the source categories. Section IV provides a summary of the final standards for newly constructed, modified, and reconstructed fossil fuel-fired steam generating units. Sections V through VII present the rationale for the final standards for newly constructed, modified, an d reconstructed steam generating units, respectively. Sections VIII and IX provide a summary of the final standard s for stationary combustion turbines and present the rati onale for the final standards for newly constructed , modified, and reconstructed combustion turbines , respectively . Section X provides a summary of other final requirements for newly constructed, modified, and reconstructed fossil fue l-fired steam generating units and stationary combustion turbines

. Section XI addresses the consistency of the respective BSER de terminations in these rules and under the emission guidelines is sued separately under CAA section 111(d). Interactions with other EPA programs and rules are described in Section XIXII . Projected*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 37 of 854 impacts of the final action are then described in S ection

XIIXIII , followed by a discussion of statutory and executi ve order reviews in Section XIII and theXIV. Section XV addresses the withdrawal of the proposed standards for steam generating EGUs that make modifications resulting in an increa se of hourly

CO 2 emissions of less than or equal to 10 percent and the proposed standards for modified stationary combusti on turbines.

The statutory authority for this action is provided in Section

XIVXVI . We address major comments throughout this preambl e and in greater detail in an accompanying response - to - comments document located in the docket. II. Background In this section , we discuss climate change impacts from GHG emissions, both on public health and public welfare . We also present information about GHG emissions from fossil - fuel - fired

EGUs , explain the uniqueness of and describe the utility power

sector , and describe recent and continuing trends and transitions in this sectorits changing structure . We then summarize the statutory and regulatory background r elevant to this final rulemaking. In addition, we provide back ground information on the EPA’s January 8, 2014 proposed c arbon pollution standards for newly constructed fossil fu el-fired EGUs, the June 18, 2014 proposed carbon pollution s tandards for modified and reconstructed EGUs, and other actions associated*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 38 of 854 with this final rulemaking. We close this section w ith a general discussion of comments and stakeholder input that t he EPA received prior to issuing this final rulemaking. A. Climate Change Impacts from GHG Emissions According to the National Research Council, “Emissi ons of

CO 2 from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the e volution of Earth’s climate. Because CO 2 in the atmosphere is long lived, it can effectively lock Earth and future generations i nto a range of impacts, some of which could become very severe. Therefore, emission reduction choices made today matter in det ermining impacts experienced not just over the next few deca des, but in the coming centuries and millennia.” 19 In 2009, based on a large body of robust and compel ling scientific evidence, the EPA Administrator issued t he Endangerment Finding under CAA section 202(a)(1). 20 In the Endangerment Finding, the Administrator found that the current, elevated concentrations of GHGs in the atmosphere — — already at levels unprecedented in human history — — may reasonably be anticipated to endanger public health and welfare o f current and

19 National Research Council, Climate Stabilization T argets, p. 3. 20 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” 7 4 Fed. Reg. 66,496FR 66496 (Dec. 15, 2009) (“Endangerment Finding”).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 39 of 854 future generations in the United States. We summari ze these adverse effects on public health and welfare briefl y here. 1. Public Health Impacts Detailed in the 2009 Endan germent Finding Climate change caused by human emissions of GHGs th reatens the health of Americans in multiple ways. By raisin g average temperatures, climate change increases the likeliho od of heat waves, which are associated with increased deaths a nd illnesses. While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the United States. Compared to a futur e without climate change, climate change is expected to incre ase ozone pollution over broad areas of the U.S., includingespecially on the highest ozone days and in the largest metropolitan areas with the worst ozone problems, and thereby increase the risk of morbidity and mortality. Climate change is also exp ected to cause more intense hurricanes and more frequent and intense storms and heavy precipitation, with impacts on oth er areas of public health, such as the potential for increased deaths, injuries, infectious and waterborne diseases, and s tress-related disorders. Children, the elderly, and the poor are among the most vulnerable to these climate-related health eff ects.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 40 of 854 2. Public Welfare Impacts Detailed in the 2009 Enda ngerment Finding Climate change impacts touch nearly every aspect of public welfare. Among the multiple threats caused by human emissions of GHGs, climate changes are expected to place large a reas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extrem e events such as floods and droughts. Coastal areas are expected to face a multitude of increased risks, particularly from ris ing sea level and increases in the severity of storms. These comm unities face

storm and floodingflood damage to property , or even loss of land due to inundation or, erosion ; as well as, wetland submergence and habitat loss. Impacts of climate change on public welfare also in clude threats to social and ecosystem services. Climate c hange is expected to result in an increase in peak electrici ty demand. Extreme weather from climate change threatens energ y, transportation, and water resource infrastructure. Climate change may also exacerbate ongoing environmental pr essures in certain settlements, particularly in Alaskan indige nous communities, and is very likely to fundamentally re arrange U.S. ecosystems over the 21 st century. Though some benefits may balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards in creasing*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 41 of 854 risks of net adverse impacts on U.S. food productio n, agriculture and forest productivity as temperature continues to rise. These impacts are global and may exacerbate p roblems outside the U.S. that raise humanitarian, trade, an d national security issues for the U.S. 3. New Scientific Assessments and Observations Since the administrative record concerning the Enda ngerment Finding closed following the EPA’s 2010 Reconsidera tion Denial, the climate has continued to change, with new recor ds being set for a number of climate indicators such as global a verage surface temperatures, Arctic sea ice retreat, CO 2 concentrations, and sea level rise. Additionally, a number of major scientific assessments have been released that improve underst anding of the climate system and strengthen the case that GHGs en danger public health and welfare both for current and future gene rations. These assessments, from the Intergovernmental Panel on Climate Change (IPCC), the U.S. Global Change Research Prog ram (USGCRP), and the National Research Council (NRC), include: I PCC’s 2012 Special Report on Managing the Risks of Extreme Eve nts and Disasters to Advance Climate Change Adaptation (SREX) and the 2013-2014 Fifth Assessment Report (AR5), the USGCRP ’s 2014 National Climate Assessment, Climate Change Impacts in the United States (NCA3), and the NRC’s 2010 Ocean Acidification: A National Strategy to Meet the Challenges of a Chang ing Ocean*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 42 of 854 (Ocean Acidification), 2011 Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts ove r Decades to Millennia (Climate Stabilization Targets), 2011 National Security Implications for U.S. Naval Forces (National Security Implications), 2011 Understanding Earth’s Deep Past: Lessons for Our Climate Future (Understanding Earth’s Deep Past), 2012 Sea Level Rise for the Coasts of California, Oregon, an d Washington: Past, Present, and Future , 2012 Climate and Social Stress: Implications for Security Analysis (Climate and Social Stress), and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts)

assessments. The EPA has carefully reviewed these recent assessm ents in keeping with the same approach outlined in Section VIIIIII .A . of the 2009 Endangerment Finding, which was to rely pr imarily upon the major assessments by the USGCRP, the IPCC, and the NRC of the National Academies to provide the technical and scientific information to inform the Administrator’s judgment regarding the question of whether GHGs endanger public health and welfare. These assessments addressed the scientific issues t hat the EPA was required to examine, were comprehensive in thei r coverage of the GHG and climate change issues, and underwent ri gorous and exacting peer review by the expert community, as we ll as rigorous levels of U.S. government review.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 43 of 854 The findings of the recent scientific assessments c onfirm and strengthen the conclusion that GHGs endanger pu blic health, now and in the future. The NCA3 indicates that huma n health in the United States will be impacted by “increased ex treme weather events, wildfire, decreased air quality, threats to mental health, and illnesses transmitted by food, water, a nd diseasecarriers such as mosquitoes and ticks.” The most re cent assessments now have greater confidence that climat e change will influence production of pollen that exacerbates ast hma and other allergic respiratory diseases such as allergic rhin itis, as well as effects on conjunctivitis and dermatitis. Both t he NCA3 and the IPCC AR5 found that increasing temperature has lengthened the allergenic pollen season for ragweed, and that increased CO 2 by itself can elevate production of plant-based all ergens. The NCA3 also finds that climate change, in additio n to chronic stresses such as extreme poverty, is negati vely affecting indigenous peoples’ health in the United States through impacts such as reduced access to tradition al foods, decreased water quality, and increasing exposure to health and safety hazards. The IPCC AR5 finds that climate cha nge-induced warming in the Arctic and resultant changes in envi ronment (e.g., permafrost thaw, effects on traditional food sources) have significant impacts, observed now and projecte d, on the health and well-being of Arctic residents, especial ly indigenous*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 44 of 854 peoples. Small, remote, predominantly-indigenous co mmunities are especially vulnerable given their “strong dependenc e on the environment for food, culture, and way of life; the ir political and economic marginalization; existing social, heal th, and poverty disparities; as well as their frequent clos e proximity to exposed locations along ocean, lake, or river sh orelines.” 21 In addition, increasing temperatures and loss of Ar ctic sea ice increases the risk of drowning for those engaged in traditional hunting and fishing. The NCA3 concludes that children’s unique physiolo gy and developing bodies contribute to making them particu larly vulnerable to climate change. Impacts on children a re expected from heat waves, air pollution, infectious and wate rborne illnesses, and mental health effects resulting from extreme weather events. The IPCC AR5 indicates that childre n are among those especially susceptible to most allergic disea ses, as well as health effects associated with heat waves, storm s, and floods. The IPCC finds that additional health conce rns may arise in low - income households, especially those with children, if

21 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects . Contribution of Working Group II to the Fifth Assessment Report of the Inte rgovernmental Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatter jee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kiss el, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. Whi te (eds.)]. Cambridge University Press, Cambridge, p. 1581.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 45 of 854 climate change reduces food availability and increa ses prices, leading to food insecurity within households. Both the NCA3 and IPCC AR5 conclude that climate ch ange will increase health risks facing the elderly. Olde r people are at much higher risk of mortality during extreme hea t events. Pre-existing health conditions also make older adul ts susceptible to cardiac and respiratory impacts of a ir pollution and to more severe consequences from infectious and waterborne diseases. Limited mobility among older adults can a lso increase health risks associated with extreme weather and fl oods. The new assessments also confirm and strengthen the conclusion that GHGs endanger public welfare, and e mphasize the urgency of reducing GHG emissions due to their proj ections that show GHG concentrations climbing to ever-increasing levels in the absence of mitigation. The NRC assessment , Understanding Earth’s Deep Past , projected that, without a reduction in emissions, CO 2 concentrations by the end of the century would increase to levels that the Earth has not experienc ed for more than 30 million years. 22 In fact, that assessment stated that “the magnitude and rate of the present greenhouse g as increase place the climate system in what could be one of th e most severe

22 National Research Council, Understanding Earth’s D eep Past, p. 1.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 46 of 854 increases in radiative forcing of the global climat e system in Earth history.” 23 Because of these unprecedented changes, several assessments state that we may be approaching critic al, poorly

understood thresholds : as. As stated in the NRC assessment Understanding Earth’s Deep Past , “As Earth continues to warm, it may be approaching a critical climate threshold bey ond which rapid and potentially permanent —at least on a human timescale— changes not anticipated by climate models tuned to modern conditions may occur.” — at least on a human timesc ale — changes not anticipated by climate models tuned to modern c onditions may

occur.” The NRC Abrupt Impacts report analyzed abrupt climate change in the physical climate system and abrupt im pacts of ongoing changes that, when thresholds are crossed, can cause abrupt impacts for society and ecosystems. The repo rt considered destabilization of the West Antarctic Ice Sheet (wh ich could cause 3-4 m of potential sea level rise) as an abru pt climate impact with unknown but probably low probability of occurring this century. The report categorized a decrease in ocean oxygen content (with attendant threats to aerobic marine l ife); increase in intensity, frequency, and duration of h eat waves; and increase in frequency and intensity of extreme precipitation events (droughts, floods, hurricanes, and major sto rms) as

23 Id., p. 138.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 47 of 854 climate impacts with moderate risk of an abrupt cha nge within this century. The NRC Abrupt Impacts report also analyzed the threat of rapid state changes in ecosystems and spe cies extinctions as examples of irreversible impacts tha t are expected to be exacerbated by climate change. Speci es at most risk include those whose migration potential is lim ited, whether because they live on mountaintops or fragmented hab itats with barriers to movement, or because climatic condition s are changing more rapidly than the species can move or adapt. While the NRC determined that it is not presently possibl e to place exact probabilities on the added contribution of cl imate change to extinction, they did find that there was substan tial risk that impacts from climate change could, within a fe w decades, drop the populations in many species below sustaina ble levels, thereby committing the species to extinction. Speci es within tropical and subtropical rainforests such as the Am azon and species living in coral reef ecosystems were identi fied by the NRC as being particularly vulnerable to extinction over the next 30 to 80 years, as were species in high latitude an d high elevation regions. Moreover, due to the time lags inherent in the Earth’s climate, the NRC Climate Stabilization Targets assessment notes that the full warming from any giv en concentration of CO 2 reached will not be fully realized for*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 48 of 854 several centuries, underscoring that emission activ ities today carry with them climate commitments far into the fu ture. Future temperature changes will depend on what emis sion path the world follows. In its high emission scenar io, the IPCC AR5 projects that average global temperatures by the end of the century will likely be 2.6 degrees Celsius (°C) to 4.8 °C (4.7 to 8.6 degrees Fahrenheit (°F)) warmer than today. Temperatures on land and in northern latitudes will likely warm even faster than the global average. However, according to the NCA3, significant reductions in emissions would lead to n oticeably less future warming beyond mid-century, and therefo re less impactsimpact to public health and welfare. While rainfall may only see small globally and annu ally averaged changes, there are expected to be substant ial shifts in where and when that precipitation falls. According to the NCA3, regions closer to the poles will see more precipita tion, while the dry subtropics are expected to expand (colloqui ally, this has been summarized as wet areas getting wetter and dry regions getting drier). In particular, the NCA3 notes that the west ern U.S., and especially the Southwest, is expected to become drier. This projection is consistent with the recent obser ved drought trend in the West. At the time of publication of th e NCA, even before the last 2 years of extreme drought in Calif ornia, tree ring data was already indicating that the region mi ght be*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 49 of 854 experiencing its driest period in 800 years. Simila rly, the NCA3 projects that heavy downpours are expected to incre ase in many regions, with precipitation events in general becom ing less frequent but more intense. This trend has already b een observed in regions such as the Midwest, Northeast, and uppe r Great Plains. Meanwhile, the NRC Climate Stabilization Ta rgets assessment found that the area burned by wildfire i s expected to grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of warming, the assessment found that 9 out of 10 summ ers would be warmer than all but the 5 percent of warmest summer s today, leading to increased frequency, duration, and inten sity of heat waves. Extrapolations by the NCA also indicate that Arctic sea ice in summer may essentially disappear by mid-cent ury. Retreating snow and ice, and emissions of carbon dioxideCO 2 and methane released from thawing permafrost, will also amplify future warming. Since the 2009 Endangerment Finding, the USGCRP NCA 3, and multiple NRC assessments have projected future rate s of sea level rise that are 40 percent larger to more than twice as large as the previous estimates from the 2007 IPCC 4 th Assessment Report due in part to improved understanding of the future rate of melt of the Antarctic and Greenland Ice sheets. The NRC Sea Level Rise assessment projects a global sea level rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) by 2100, the NRC National Security*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 50 of 854 Implications assessment suggests that “the Department of the Navy should expect roughly 0.4 to 2 meters [( 1.3 to 6.6 feet ]) global average sea-level rise by 2100,” 24 and the NRC Climate Stabilization Targets assessment states that an increase of 3 °C will lead to a sea level rise of 0.5 to 1 meter (1. 6 to 3.3 feet) by 2100. These assessments continue to recogn ize that there is uncertainty inherent in accounting for ice sheet processes. Additionally, local sea level rise can d iffer from the global total depending on various factors : the. The east coast of the U.S. in particular is expected to see higher rates of sea level rise than the global average. For comp arison, the NCA3 states that “five million Americans and hundre ds of billions of dollars of property are located in area s that are less than four feet above the local high-tide level ,” and the NCA3 finds that “[c]oastal infrastructure, includin g roads, rail lines, energy infrastructure, airports, port facili ties, and military bases, are increasingly at risk from sea l evel rise and damaging storm surges.” 25 Also, because of the inertia of the oceans, sea level rise will continue for centuries after greenhouse gasGHG concentrations have stabilized (though more

24 NRC, 2011: National Security Implications of Climate Change for U.S. Naval Forces . The National Academies Press, p. 28. 25 Melillo, Jerry M., Terese (T.C.) Richmond, and Gar y W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, p. 9.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 51 of 854 slowly than it would have otherwise). Additionally, there is a threshold temperature above which the Greenland ice sheet will be committed to inevitable melting : according. According to the NCA, some recent research has suggested that even p resent day carbon dioxideCO 2 levels could be sufficient to exceed that

threshold. In general, climate change impacts are expected to be unevenly distributed across different regions of th e United States and have a greater impact on certain populat ions, such as indigenous peoples and the poor. The NCA3 finds that climate change impacts such as the rapid pace of temperatur e rise, coastal erosion and inundation related to sea level rise and storms, ice and snow melt, and permafrost thaw are affecting indigenous people in the United StatesU.S . Particularly in Alaska, critical infrastructure and traditional liv elihoods are threatened by climate change and, “[i]n parts of Al aska, Louisiana, the Pacific Islands, and other coastal l ocations, climate change impacts (through erosion and inundat ion) are so severe that some communities are already relocating from historical homelands to which their traditions and cultural identities are tied.” 26 The IPCC AR5 notes, “Climate-related

26 Melillo, Jerry M., Terese (T.C.) Richmond, and Gar y W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, p. 17.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 52 of 854 hazards exacerbate other stressors, often with nega tive outcomes for livelihoods, especially for people living in po verty (high confidence). Climate-related hazards affect poor p eople’s lives directly through impacts on livelihoods, reductions in crop yields, or destruction of homes and indirectly thro ugh, for example, increased food prices and food insecurity. ” 27

Carbon dioxideCO 2 in particular has unique impacts on ocean ecosystems. The NRC Climate Stabilization Targets assessment found that coral bleaching will increase due both t o warming and ocean acidification. Ocean surface waters have alre ady become 30 percent more acidic over the past 250 years due to absorption of

CO 2 from the atmosphere. According to the NCA3, this acidification will reduce the ability of organisms such as corals, krill, oysters, clams, and crabs to survive , grow, and reproduce. The NRC Understanding Earth's Deep Past assessment

notes that four of the five major coral reef crises of the pas t 500 million years were caused by acidification and warming that followed GHG increases of similar magnitude to the emissions increases expected over the next hundred years. The NRC Abrupt

27 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C .B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T .E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, p. 796.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 53 of 854 Impacts assessment specifically highlighted similarities b etween the projections for future acidification and warmin g and the extinction at the end of the Permian which resulted in the loss of an estimated 90 percent of known species. Similarly, the NRC Ocean Acidification assessment finds that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic carbon dioxideCO 2 emissions; the rate of change exceeds any known to have occurred for at least the past hundreds of thousands of years.” 28 The assessment notes that the full range of consequences is still unknown, but th e risks “threaten coral reefs, fisheries, protected species , and other natural resources of value to society.” 29 Events outside the United States, as also pointed o ut in the 2009 Endangerment Finding, will also have relev ant consequences. The NRC Climate and Social Stress assessment concluded that it is prudent to expect that some cl imate events “will produce consequences that exceed the capacity of the affected societies or global systems to manage and that have global security implications serious enough to comp el international response.” The NRC National Security Implications assessment recommends preparing for increased needs for

28 NRC, 2010: Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean . The National Academies Press, p. 5. 29 Ibid Id

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 54 of 854 humanitarian aid; responding to the effects of clim ate change in geopolitical hotspots, including possible mass migr ations – and cites Egypt and Pakistan as two case studies of pot ential security issues linked to climate change within the next 10

years 30 ; and addressing changing security needs in the Arc tic as sea ice retreats. In addition to future impacts, the NCA3 emphasizes that climate change driven by human emissions of GHGs is already happening now and it is happening in the United Sta tes. According to the IPCC AR5 and the NCA3, there are a number of climate-related changes that have been observed rec ently, and these changes are projected to accelerate in the fu ture. The planet warmed about 0.85 °C (1.5 °F) from 1880 to 2 012. It is extremely likely (>95 percent probability) that hum an influence was the dominant cause of the observed warming sinc e the mid-20 th century, and likely (>66 percent probability) that human influence has more than doubled the probability of occurrence of heat waves in some locations. In the Northern Hemis phere, the last 30 years were likely the warmest 30 - year period of the

30 NRC, 2011: National Security Implications of Climate Change for U.S. Naval Forces . The National Academies Press, p. 121 (“Of the many places in the world where climate dynamics might induce globally consequential disruption within a decade, Egypt is a principal possibility.”); p. 122 (“Pakistan present s a clear example of a country where social dynamics and susc eptibility to harm from climate events combine to create a potent ially unstable situation.”).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 55 of 854

last 1,4001400 years. U.S. average temperatures have similarly increased by 1.3 to 1.9 degrees ° F since 1895, with most of that increase occurring since 1970. Global sea levels ro se 0.19 m (7.5 inches) from 1901 to 2010. Contributing to thi s rise was the warming of the oceans and melting of land ice. It is likely that 275 Gt/gigatons per year of ice have melted from land glaciers (not including ice sheets) since 1993, and that the rate of loss of ice from the Greenland and Antarcti c ice sheets

has increased substantially in recent years, to 215 Gt/gigatons

per year and 147 Gt/gigatons per year respectively , since 2002. For context, 360 Gtgigatons of ice melt will is sufficient to cause global sea levels to rise 1 mm. Annual mean A rctic sea ice has been declining at 3.5 to 4.1 percent per decade , and Northern Hemisphere snow cover extent has decreased at about 1.6 percent per decade for March and 11.7 percent per d ecade for June. Permafrost temperatures have increased in mos t regions since the 1980s, by up to 3 °C (5.4 °F) in parts of Northern Alaska. Winter storm frequency and intensity have b oth increased in the Northern Hemisphere. The NCA3 states that th e increases in the severity or frequency of some types of extre me weather and climate events in recent decades can affect ene rgy production and delivery, causing supply disruptions , and compromise other essential infrastructure such as w ater and transportation systems.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 56 of 854 In addition to the changes documented in the assess ment literature, there have been other climate milestone s of note. In 2009, the year of the Endangerment Finding, the ave rage concentration of CO 2 as measured on top of Mauna Loa was 387 parts per million, far above preindustrial concentr ations of about 280 parts per million. 31 The average concentration in 2013, the last full year before this rule was proposed, w as 396 parts per million. The average concentration in 2014 was 399 parts per million. And the monthly concentration in April of 2014 was 401 parts per million, the first time a monthly average has exceeded 400 parts per million since record keeping began at Mauna Loa in 1958, and for at least the past 800,000 years

. 32 based on ice

core records. 33 Arctic sea ice has continued to decline, with September of 2012 marking a new record low in terms of Arctic sea ice extent, 40 percent below the 1979-2000 medi an. Sea level has continued to rise at a rate of 3.2 mm per year (1.3 inches/decade) since satellite observations started in 1993, more than twice the average rate of rise in the 20 th century prior to 1993. 34 And 2014 was the warmest year globally in the

31 ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_an nmean_mlo.txt 32 http://www.esrl.noaa.gov/gmd/ccgg/trends/. 33 http://www.esrl.noaa.gov/gmd/ccgg/trends/. 34 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 57 of 854 modern global surface temperature record, going bac k to 1880; this now means 19 of the 20 warmest years have occu rred in the past 20 years, and except for 1998, the ten warmest years on record have occurred since 2002. 35 The first months of 2015 have

also been some of the warmest on record. These assessments and observed changes make it clea r that reducing emissions of GHGs across the globe is nece ssary in order to avoid the worst impacts of climate change, and underscore the urgency of reducing emissions now. T he NRC Committee on America’s Climate Choices listed a num ber of reasons “why it is imprudent to delay actions that at least begin the process of substantially reducing emissio ns.” 36 For example:

• The faster emissions are reduced, the lower the ris ks posed by climate change. Delays in reducing emissio ns could commit the planet to a wide range of adverse impacts, especially if the sensitivity of the clima te to greenhouse gases is on the higher end of the estima ted range.

• Waiting for unacceptable impacts to occur before ta king action is imprudent because the effects of greenhou se gas emissions do not fully manifest themselves for deca des and, once manifest, many of these changes will pers ist for hundreds or even thousands of years.

• In the committee’s judgment, the risks associated w ith doing business as usual are a much greater concern than

35 http://www.ncdc.noaa.gov/sotc/global/2014/13

. 36 NRC, 2011: America’s Climate Choices , The National Academies Press.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 58 of 854 the risks associated with engaging in strong respon se efforts. 4. Observed and Projected U.S. Regional Changes The NCA3 assessed the climate impacts in 8eight regions of the United States, noting that changes in physical climate parameters such as temperatures, precipitation, and sea ice retreat were already having impacts on forests, wat er supplies, ecosystems, flooding, heat waves, and air quality. Moreover, the NCA3 found that future warming is projected to be m uch larger than recent observed variations in temperature, wit h precipitation likely to increase in the northern st ates, decrease in the southern states, and with the heavi est precipitation events projected to increase everywhe re. In the Northeast, temperatures increased almost 2 ° F from 1895 to 2011, precipitation increased by about 5 in ches (10 percent), and sea level rise of about a foot has le d to an increase in coastal flooding. The 70 percent increa se in the amount of rainfall falling in the 1 percent of the most intense events is a larger increase in extreme precipitatio n than experienced in any other USU.S. region. In the future, if emissions continue increasing, th e Northeast is expected to experience 4.5 to 10 °F of warming by the 2080s. This will lead to more heat waves, coast al and river flooding, and intense precipitation events. The southern portion*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 59 of 854 of the region is projected to see 60 additional day s per year above 90 °F by mid-century. Sea levels in the Northeast are expected to increase faster than the global average because of subsidence, and changing ocean currents may further increase the rate of sea level rise. Specific vulnerabilities hi ghlighted by the NCA include large urban populations particularl y vulnerable to climate-related heat waves and poor air quality episodes, prevalence of climate sensitive vector-borne diseas es like Lyme and West Nile Virus, usage of combined sewer system s that may lead to untreated water being released into local w ater bodies after climate-related heavy precipitation events, a nd 1.6 million people living within the 100-year coastal f lood zone who are expected to experience more frequent floods due to sea level rise and tropical-storm induced storm-surge. The NC A also highlighted infrastructure vulnerable to inundation in coastal metropolitan areas, potential agricultural impacts from increased rain in the spring delaying planting or d amaging crops or increased heat in the summer leading to decrease d yields and increased water demand, and shifts in ecosystems le ading to declines in iconic species in some regions, such as cod and lobster south of Cape Cod. In the Southeast, average annual temperature during the last century cycled between warm and cool periods. A warm peak occurred during the 1930s and 1940s , followed by a cool period ,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 60 of 854 and temperatures then increased again from 1970 to the present by an average of 2 °F. There have been increasing n umbers of days above 95 °F and nights above 75 °F, and decrea sing numbers of extremely cold days since 1970. Daily and five-d ay rainfall intensities have also increased, and summers have b een either increasingly dry or extremely wet. Louisiana has already lost 1,880 square miles of land in the last 80 years due to sea level rise and other contributing factors. The Southeast is exceptionally vulnerable to sea le vel rise, extreme heat events, hurricanes, and decrease d water availability. Major consequences of further warming include significant increases in the number of hot days (95 °F or above) and decreases in freezing events, as well as exacer bated groundlevel ozone in urban areas. Although projected warm ing for some parts of the region by the year 2100 areis generally smaller than for other regions of the United States, projec ted warming for interior states of the region areis larger than coastal regions by 1 °F to 2 °F. Projections further sugges t that globally there will be fewer tropical storms globally , but that they will be more intense, with more Category 4 and 5 storms. The NCA identified New Orleans, Miami, Tampa, Charl eston, and Virginia Beach as being specific cities that are at risk due to sea level rise, with additionalhomes and infrastructure increasingly prone to flooding. Additional impacts onof sea*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 61 of 854 level rise are expected for coastal highways, wetlands, and energy andfresh water supplies , and energy infrastructure

. In the Northwest, temperatures increased by about 1

. 3 o F3 o F between 1895 and 2011. A small average increase in precipitation was observed over this time period. However, warmin g temperatures have caused increased rainfall relativ e to snowfall, which has altered water availability from snowpack across parts of the region. Snowpack in the Northwe st is an important freshwater source for the region. More pr ecipitation falling as rain instead of snow has reduced the sno wpack, and warmer springs have corresponded to earlier snowpac k melting and reduced streamflows during summer months. Drier con ditions have increased the extent of wildfires in the region. Average annual temperatures are projected to increa se by 3. 3 o F3 o F to 9. 7 o F7 o F by the end of the century (depending on future global greenhouse gasGHG emissions), with the greatest warming is expected during the summer. Continued increases in global greenhouse gasGHG emissions are projected to result in up to a 30 percent decrease in summer precipitation. E arlier snowpack melt and lower summer streamflowsstream flows are expected by the end of the century and will affect drinking water supplies, agriculture, ecosystems, and hydrop ower production. Warmer waters are expected to increase disease and mortality in important fish species, including Chin ook and*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 62 of 854 sockeye salmon. Ocean acidification also threatens species such as oysters, with the Northwest coastal waters alrea dy being some of the most acidified worldwide due to coastal upwe lling and

other local factors. Forest pests are expected to spread and wildfires to burn larger areas. Other high-elevation ecosystems are projected to be lost because they can no longer survive the climatic conditions. Low lying coastal areas, inclu ding the cities of Seattle and Olympia, will experience heig htened risks of sea level rise, erosion, seawater inundation and damage to infrastructure and coastal ecosystems. In Alaska, temperatures have changed faster than an ywhere else in the United States. Annual temperatures incr eased by about 3 °F in the past 60 years. Warming in the win ter has been even greater, rising by an average of 6 °F. Arctic sea ice is thinning and shrinking in area, with the summer min imum ice extent now covering only half the area it did when satellite records began in 1979. Glaciers in Alaska are melti ng at some of the fastest rates on Earth. Permafrost soils are al so warming and beginning to thaw. Drier conditions have contri buted to more large wildfires in the last 10 years than in any pr evious decade since the 1940s, when recordkeeping began. Climate change impacts are harming the health, safety , and livelihoods of Native Alaskan communities.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 63 of 854 By the end of this century, continued increases in greenhouse gasGHG emissions are expected to increase temperatures by 10 to 12 °F in the northernmost par ts of Alaska, by 8 to 10 °F in the interior, and by 6 to 8 °F acr oss the rest of the state. These increases will exacerbate ongoi ng Arcticarctic sea ice loss, glacial melt, permafrost thaw and increased wildfire, and threaten humans, ecosystems , and infrastructure. Precipitation is expected to increa se to varying degrees across the state , however. However, warmer air temperatures and a longer growing season are expect ed to result in drier conditions. Native Alaskans are expected t o experience declines in economically, nutritionally, and cultur ally important wildlife and plant species. Health threat s will also increase, including loss of clean water, saltwater intrusion, sewage contamination from thawing permafrost, and n orthward extension of diseases. Wildfires will increasingly pose threats to human health as a result of smoke and direct con tact. Areas underlain by ice-rich permafrost across the state a re likely to experience ground subsidence and extensive damage t o infrastructure as the permafrost thaws. Important e cosystems will continue to be affected. Surface waters and we tlands that are drying provide breeding habitat for millions of waterfowl and shorebirds that winter in the lower 48 states. Warmer ocean temperatures, acidification, and declining sea ice will*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 64 of 854 contribute to changes in the location and availabil ity of commercially and culturally important marine fish. In the Southwest, temperatures are now about 2 °F h igher than the past century, and are already the warmest that region has experienced in at least 600 years. The NCA note s that there is evidence that climate - change - induced warming on top of recent drought has influenced tree mortality, wildf ire frequency and area, and forest insect outbreaks. Sea levels h ave risen about 7 or 8 inches in this region, contributing to inundation of Highway 101 and backup of seawater into sewage s ystems in the San Francisco area. Projections indicate that the Southwest will warm a n additional 5.5 to 9.5 °F over the next century if e missions continue to increase. Winter snowpack in the Southw est is projected to decline (consistent with the record lo ws from this past winter), reducing the reliability of surface w ater supplies for cities, agriculture, cooling for power plants, and ecosystems. Sea level rise along the California coast will worsen coastal erosion, increase flooding risk for coastal highways, bridges, and low-lying airports, pose a t hreat to groundwater supplies in coastal cities such as Los Angeles, and increase vulnerability to floods for hundreds of th ousands of residents in coastal areas. Climate change will also have impacts on the high-value specialty crops grown in the region as*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 65 of 854 a drier climate will increase demands for irrigatio n, more frequent heat waves will reduce yields, and decreas ed winter chills may impair fruit and nut production for tree s in California. Increased drought, higher temperatures, and bark beetle outbreaks are likely to contribute to contin ued increases in wildfires. The highly urbanized population of th e Southwest is vulnerable to heat waves and water supply disrup tions, which can be exacerbated in cases where high use of air c onditioning triggers energy system failures. The rate of warming in the Midwest has markedly acc elerated over the past few decades. Temperatures rose by mor e than 1.5 °F from 1900 to 2010, but between 1980 and 2010 , the rate of warming was three times faster than from 1900 throu gh 2010. Precipitation generally increased over the last cen tury, with much of the increase driven by intensification of t he heaviest rainfalls. Several types of extreme weather events in the Midwest (e.g., heat waves and flooding) have alread y increased in frequency and/or intensity due to climate change

. In the future, if emissions continue increasing, th e Midwest is expected to experience 5.6 to 8.5 °F of warming by the 2080s, leading to more heat waves. Though proje ctions of changes in total precipitation vary across the regi ons, more precipitation is expected to fall in the form of he avy downpours across the entire region, leading to an increase in flooding.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 66 of 854 Specific vulnerabilities highlighted by the NCA inc lude longterm decreases in agricultural productivity, change s in the composition of the region’s forests, increased publ ic health threats from heat waves and degraded air and water quality, negative impacts on transportation and other infras tructure associated with extreme rainfall events and floodin g, and risks to the Great Lakes including shifts in invasive spe cies, increases in harmful algal blooms, and declining be ach health. High temperatures (more than 100 °F in the Souther n PlainPlains and more than 95 °F in the Northern Plains) are projected to occur much more frequently by mid-cent ury. Increases in extreme heat will increase heat stress for residents, energy demand for air conditioning, and water losses. North Dakota’s increase in annual temperatures over the past 130 years is the fastest in the contiguous U.S., mainly driven by warming winters. Specific vulnerabilities highlight ed by the NCA include increased demand for water and energy, chan ges to crop - growth cycles and agricultural practices, and negat ive impacts on local plant and animal species from habitat frag mentation, wildfires, and changes in the timing of flowering o r pest patterns. Communities that are already the most vul nerable to weather and climate extremes will be stressed even further by more frequent extreme events occurring within an al ready highly variable climate system.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 67 of 854 In Hawaii, other Pacific islands, and the Caribbean , rising air and ocean temperatures, shifting rainfall patte rns, changing frequencies and intensities of storms and drought, decreasing baseflow in streams, rising sea levels, and changin g ocean chemistry will affect ecosystems on land and in the oceans, as well as local communities, livelihoods, and culture s. Low islands are particularly at risk. Rising sea levels, coupled with high water levels c aused by tropical and extra-tropical storms, will incrementa lly increase coastal flooding and erosion, damaging coastal ecos ystems, infrastructure, and agriculture, and negatively aff ecting tourism. Ocean temperatures in the Pacific region e xhibit strong year-to-year and decadal fluctuations, but since th e 1950s, they have exhibited a warming trend, with temperatures f rom the surface to a depth of 660 feet rising by as much as 3.6 °F. As a result of current sea level rise, the coastline of Puerto Rico around Rincón is being eroded at a rate of 3.3 feet per year. Freshwater supplies are already constrained and wil l become more limited on many islands. Saltwater intrusion associ ated with sea level rise will reduce the quantity and quality of freshwater in coastal aquifers, especially on low islands. In are as where precipitation does not increase, freshwater supplie s will be adversely affected as air temperature rises.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 68 of 854 Warmer oceans are leading to increased coral bleach ing events and disease outbreaks in coral reefs, as wel l as changed distribution patterns of tuna fisheries. Ocean acid ification will reduce coral growth and health. Warming and ac idification, combined with existing stresses, will strongly affe ct coral - reef fish communities. For Hawaii and the Pacific islands, future sea surface temperatures are projected to in crease 2.3 °F by 2055 and 4.7 °F by 2090 under a scenario that as sumes continued increases in emissions. Ocean acidificati on is also taking place in the region, which adds to ecosystem stress from increasing temperatures. Ocean acidity has increase d by about 30 percent since the pre-industrial era and is project ed to further increase by 37 percent to 50 percent from present levels by 2100. The NCA also discussed impacts that occur along the coasts and in the oceans adjacent to many regions, and not ed that other impacts occur across regions and landscapes in ways that do not follow political boundaries. B. GHG Emissions from Fossil Fuel-fired EGUs Fossil fuel-fired electric utility generating units (EGUs)EGUs are by far the largest emitters of GHGs among stationary sources in the U.S., primarily in the fo rm of CO 2. Among fossil fuel-fired EGUs, coal-fired units are by far the largest emitters. This section describes the amount s of these*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 69 of 854 emissions and places these amounts in the context o f the U.S. Inventory of Greenhouse Gas Emissions and Sinks 37 (the U.S. GHG Inventory). The EPA implements a separate program under 40 CFR part 98 called the Greenhouse Gas Reporting Program 38 (GHGRP) that requires emitting facilities that emit over certain threshold amounts of GHGs to report their emissions to the EPA annually. Using data from the GHGRP, this section also places emissions from fossil fuel-fired EGUs in the context of the t otal emissions reported to the GHGRP from facilities in the other largest-emitting industries. The EPA prepares the official U.S. GHG Inventory to comply with commitments under the United Nations Framework Convention on Climate Change (UNFCCC). This inventory, which i ncludes recent trends, is organized by industrial sectorssector . It provides the information in Table 3 below, which pr esents total

37 “Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990 – 2013”, Report EPA 430-R-15-004, United States Envir onmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinvento ryreport.html 38 U.S. EPA Greenhouse Gas Reporting Program Dataset, see http://www.epa.gov/ghgreporting/ghgdata/reportingda tasets.html.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 70 of 854 U.S. anthropogenic emissions and sinks 39 of GHGs, including CO 2 emissions, for the years 1990, 2005 and 2013. Table 3. U.S. GHG Emissions and Sinks by Sector (mi llion metric tons carbon dioxide equivalent (MMT CO 2 Eq.))CO 2 e)) 40, 41

SECTOR 1990 2005 2013 Energy 42 5,290.5 6,273.6 5,636.6 Industrial Processes and Product Use 342.1 367.4 359.1 Agriculture 448.7 494.5 515.7 Land Use, Land-Use Change and Forestry 13.8 25.5 23.3 Waste 206.0 189.2 138.3 Total Emissions 6,301.1 7,350.2 6,673.0 Land Use, Land-Use Change and Forestry (Sinks) (775.8) (911.9) (881.7)

39 Sinks are a physical unitunits or processprocesses that storesstore GHGs, such as forests or underground or deep sea reservoirs of carbon dioxideCO 2 . 40 From Table ES-4 of “Inventory of U.S. Greenhouse G as Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, U nited States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinvento ryreport.html 41 From Table ES-4 of “Inventory of U.S. Greenhouse G as Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, U nited States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinvento ryreport.html 1 metric ton (tonne) is equivalent to 1,000 kilogra ms (kg) and is equivalent to 1.1023 short tons or 2,204.62 poun ds (lb). 42 The energy sector includes all greenhouse gases re sulting from stationary and mobile energy activities including f uel combustion and fugitive fuel emissions.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 71 of 854 Net Emissions (Sources and Sinks) 5,525.2 6,438.3 5,791.2

Total fossil energy-related CO 2 emissions (including both stationary and mobile sources) are the largest cont ributor to total U.S. GHG emissions, representing 77.3 percent of total 2013 GHG emissions. 43 In 2013, fossil fuel combustion by the utility power sector

–-– entities that burn fossil fuel and whose primary business is the generation of electri city

–-– accounted for 38.3 percent of all energy-related CO 2 emissions. 44 Table 4 below presents total CO 2 emissions from fossil fuel-fired EGUs, for years 1990, 2005 , and 2013. Table 4. U.S. GHG Emissions from Generation of Elec tricity from Combustion of Fossil Fuels (MMT CO 2 ) 45

43 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, U nited States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinvento ryreport.html

. 44 From Table 3-1 “Inventory of U.S. Greenhouse Gas E missions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, Unite d States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinvento ryreport.html 45 From Table 3-5 “Inventory of U.S. Greenhouse Gas E missions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, Unite d States Environmental Protection Agency, April 15 2015. http://epa.gov/climatechange/ghgemissions/usinvento ryreport.html

. GHG EMISSIONS 1990 2005 2013

Total CO 2 from fossil fuelfired EGUs 1,820.8 2,400.9 2,039.8*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 72 of 854

In addition to preparing the official U.S. GHG Inve ntory to present comprehensive total U.S. GHG emissions and comply with commitments under the UNFCCC, the EPA collects deta iled GHG emissions data from the largest emitting facilities in the U.S. through its Greenhouse Gas Reporting Program (GHGRP).GHGRP. Data collected by the GHGRP from large stationary source s in the industrial sector show that the utility power secto r emits far greater CO 2 emissions than any other industrial sector. Table 5 below presents total GHG emissions in 2013 for the largest emitting industrial sectors as reported to the GHGR P. As shown in Table 4 and Table 5, respectively, carbon dioxideCO 2 emissions from fossil fuel-fired EGUs are nearly three times as large as the total reported GHG emissions from the next ten largest emitting industrial sectors in the GHGRP database c ombined. Table 5. Direct GHG Emissions Reported to GHGRP by Largest Emitting Industrial Sectors (MMT CO 2 e) 46

46 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do. - from coal 1,547.6 1,983.8 1,575.0 - from natural gas 175.3 318.8 441.9 - from petroleum 97.5 97.9 22.4

Industrial Sector 2013 Fossil Fuel-fired EGUs 2,039.8 Petroleum Refineries 176.7*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 73 of 854

It should be noted that the discussion above conce rned all fossil fuel-fired EGUs. Steam generators emitted 1, 627 MMT CO 2 e and combustion turbines emitted 401 MMT CO 2 e in 2013. 47 C. The Utility Power Sector 1. Modern Electric System Trends The EPA includes a background discussion of the el ectricity system in the Clean Power Plan (CPP) rulemaking, wh ich is the companion rulemaking to this rule that promulgates emission guidelines for states to use in regulating emission s of CO 2 from existing fossil fuel-fired EGUs. Readers are referr ed to that rulemaking. The following discussion of electricity sector trends is of particular relevance for this rulemaki ng. The electricity sector is undergoing a period of in tense change. Fossil fuels – such as coal, natural gas, a nd oil – have historically provided a large percentage of electri city in the

47 These figures are based on data for EGUs in the Ac id Rain Program plus additional ones that report to the EPA under the Regional Greenhouse Gas Initiative. Onshore Oil & Gas Production 94.8 Municipal Solid Waste Landfills 93.0 Iron & Steel Production 84.2 Cement Production 62.8 Natural Gas Processing Plants 59.0 Petrochemical Production 52.7 Hydrogen Production 41.9 Underground Coal Mines 39.8 Food Processing Facilities 30.8*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 74 of 854 U.S., with smaller amounts being provided by other types of generation , including nuclear , and renewables such as wind, solar, and hydroelectric power. Coal has historically provided the largest percentage of the fossil - fuel generation. 48 In recent years, the nation has seen a sizeable increa se in renewable generation such as wind and solar, as wel l as a shift from coal to natural gas. 49

. In 2013, fossil fuels supplied 67 percent of U.S. electricity, but renewables made up 38 percent of the new generation capacity (over 5 GW out of 13 .5 GW). 50 From 2007 to 2014, use of lower- and zero-carbon energy sources has grown, while other major energy sources such as coa l and oil have experienced declines. Renewable electricity ge neration, including from large hydro-electric projects, grew from 8

48 U.S. Energy Information Administration, “Table 7.2 b Electricity Net Generation: Electric Power Sector” data from April 2014 Monthly Energy Review, release data Apri l 25, 2014, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec 7_6.pdf. 49 U.S. Energy Information Administration, “Table 7.2 b Electricity Net Generation: Electric Power Sector” data from April 2014 Monthly Energy Review, release data Apri l 25, 2014, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec 7_6.pdf. 50 Based on Table 6.3 (New Utility Scale Generating U nits by Operating Company, Plant, Month, and Year) of the U .S. Energy Information Administration (EIA) Electric Power Mon thly, data for December 2013, for the following renewable ener gy sources: solar, wind, hydro, geothermal, landfill gas, and b iomass. Available at: http:// www.eia.gov/electricity/monthly/epm_table_grapher.c fm?t=epmt_6_0 3.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 75 of 854 percent to 13 percent over that time period. 51 Between 2000 and 2013, approximately 90 percent of new power generat ion capacity built in the U.S. has come in the form of natural g as or renewable energy facilities. 52 In 2015, the U.S. Energy Information Administration’sAdministration (EIA) projected the need for 28.4 GW of additional base load or interme diate load generation capacity through 2020, with approximatel y 0.7 GW of new coal-fired capacity, 5.5 GW of new nuclear capa city, and 14.2 GW of new NGCC capacity already in development

. 53 The change in the resource mix has accelerated in r ecent years, but wind, solar, other renewables, and energ y - efficiency resources have been reliably participating in the e lectric sector for a number of years. This rapid developmen t of nonfossil fuel resources is occurring as much of the e xisting power generation fleet in the U.S. is aging and in need o f

51 Bloomberg New Energy Finance and the Business Coun cil for Sustainable Energy , 2015 Factbook: Sustainable Energy in America , at 16 (2015), available at http://www.bcse.org/images/2015%20Sustainable%20Ene rgy%20in%20Am erica%20Factbook.pdf. 52 Energy Information Administration, Electricity: Form EIA-860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/. 53 EIA, Annual Energy Outlook for 2015 with Projections to 2040 , Final Release, available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015). pdf. The The AEO numbers include projects that are under development and modelprojected nuclear, coal, and NGCC projects.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 76 of 854 modernization and replacement. 54 For example, the average age of U.S. coal steam units in 2015 is 45 years . 55 In its 2013 Report Card for America’s Infrastructure , the American Society for Civil Engineers noted that “America relies on an ag ing electrical grid and pipeline distribution systems, some of which originated in the 1880s.” 56 While there has been an increased investment in electric transmission infrastructure since 2005, the report also found that “ongoing permitting issu es, weather events, and limited maintenance have contributed to an increasing number of failures and power interruptio ns.” 57 However, innovative technologies have increasingly entered the electric energy space, helping to provide new answe rs to how to meet the electricity needs of the nation. These new technologies can enable the nation to answer not just questions as to how to reliably meet electricity demand, but also how to m eet

54 Quadrennial Energy Review, http://energy.gov/epsa/ quadrennialenergy-review-qer 55 We calculated the average age of coal steam units based on the NEEDS inventory (a “snapshot” of the sector in 2016),, and adding backincluded units with actual/ planned retirements in 20122015 -2016. See http://www.epa.gov/airmarkets/documents/ipm/needs_v 514.xlsx. 56 American Society for Civil Engineers, 2013 Report Card for America’s Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/. 57 American Society for Civil Engineers, 2013 Report Card for America’s Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 77 of 854 electricity demand reliably and cost-effectively 58 with the lowest possible emissions and the greatest efficien cy. Natural gas has a long history of meeting electrici ty demand in the U.S. with a rapidly growing role as d omestic supplies of natural gas have dramatically increased . Natural gas net generation increased by approximately 36 percen t between 2004 and 2014. 59 In 2014, natural gas accounted for approximately 27 percent of net generation. 60 The EIA projects that this demand growth will continue , with its Annual Energy Outlook 2015 (AEO 2015) Referencereference case forecasting that natural gas will produce 31 percent of U.S. electric generation in 2 040. 61 Renewable sources of electric generation also have a history of meeting electricity demand in the U.S. a nd are expected to have an increasing role going forward. A series of

58 Business Council for Sustainable Energy Comments i n Docket Id. No. EPA-HQ-OAR-2013-0602 at 2 (Nov. 19, 2014). 59 U.S. Energy Information Administration (EIA), Electric Power Monthly: Table 1.1 Net Generation by Energy Source: Total (All Sectors), 2004-December 2014 (2015), available at http://www.eia.gov/electricity/monthly/epm_table_gr apher.cfm?t=e pmt_1_1. 60 Id. 61 The AEO 2015 Reference case projection is a busine ss-as-usual trend estimate, given known technology and technolo gical and demographic trends. EIA explores the impacts of alt ernative assumptions in other cases with different macroecon omic growth rates, world oil prices, and resource assumptions. U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at 24-25 (2015), available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 78 of 854 energy crises provided the impetus for renewable en ergy development in the early 1970s. The OPEC oil embarg o in 1973 and oil crisis of 1979 caused oil price spikes, more fr equent energy shortages, and significantly affected the national and global economy. In 1978, partly in response to fuel securi ty concerns, Congress passed the Public Utilities Regulatory Pol icies Act (PURPA) which required local electric utilities to buy power from qualifying facilities (QFs). 62 QFs were either cogeneration facilities 63 or small generation resources that use renewables such as wind, solar, biomass, geothermal, or hydroe lectric power as their primary fuels. 64 Through PURPA, Congress supported the development of more renewable energy generation in the U.S. States have taken a significant lead in requiring t he development of renewable resources. In particular, a number of states have adopted renewable portfolio standards ( RPS). As of 2013, 29 states and the District of Columbia have e nforceable RPS or similar laws. 65 In its AEO 2015 Reference case, the EIA

62 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 63 Cogeneration facilities utilize a single source of fuel to produce both electricity and another form of energy such as heat or steam. Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 64 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 65 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2014 with Projections to 2040 , at LR-5 (2014).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 79 of 854 found that renewable energy will account for 38 per cent of the overall growth in electricity generation from 2013 to 2040. 66 The AEO 2015 Reference case forecasts that the renewabl es share of U.S. electricity generation will grow from 13 perce nt in 2013 to 18 percent in 2040. 67 Price pressures caused by oil embargoes in the 1970 s also brought the issues of conservation and energy effic iency to the forefront of U.S. energy policy. 68 This trend continued in the early 1990s. Some state regulatory commissions and utilities supported energy efficiency through least-cost plan ning, with the National Association of Regulatory Utility Comm issioners (NARUC) “adopting a resolution that called for the utility’s

66 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at E-12(2015). 67 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at 24-25(2015). 68 Edison Electric Institute, Making a Business of Energy Efficiency: Sustainable Business Models for Utiliti es , at 1 (2007). Congress passed legislation in the 1970s t hat jumpstarted energy efficiency in the U.S. For exam ple, President Ford signed the Energy Policy and Conserv ation Act (EPCA) of 1975 – the first law on the issue. EPCA authorized the Federal Energy Administration (FEA) to “develop energy conservation contingency plans, established vehicle fuel economy standards, and authorized the creation of efficienc y standards for major household appliances.” Alliance to Save Energy, History of Energy Efficiency , at 6 (2013) (citing Anders, “The Federal Energy Administration,” 5; Energy Policy and Conservation Act, S. 622, 94th Cong. (1975-1976)), available at https://www.ase.org/sites/ase.org/files/resources/M edia%20browse r/ee_commission_history_report_2-1-13.pdf.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 80 of 854 least cost plan to be the utility’s most profitable plan.” 69 Energy efficiency has been utilized to meet energy demand to varying levels since that time. As of April 2014, 2 5 states 70 have “enacted long-term (3+ years), binding energy savings targets, or energy efficiency resource standards (E ERS).” 71 Funding for energy efficiency programs has grown ra pidly in recent years, with budgets for electric efficiency programs totaling $5.9 billion in 2012. 72 Advancements and innovation in power sector techno logies provide the opportunity to address CO 2 emission levels at affected power plants while at the same time improv ing the overall power system in the U.S. by lowering the ca rbon

69 Edison Electric Institute, Making a Business of Energy Efficiency: Sustainable Business Models for Utiliti es , at 1 (2007), available at http://www.eei.org/whatwedo/PublicPolicyAdvocacy/St ateRegulation /Documents/Making_Business_Energy_Efficiency.pdf

. 70 American Council for an Energy-Efficient Economy, State Energy Efficiency Resource Standards (EERS) (2014), available at http://aceee.org/files/pdf/policy-brief/eers-04-201 4.pdf. ACEEE did not include Indiana (EERS eliminated), Delaware (EERS pending), Florida (programs funded at levels far be low what is necessary to meet targets), Utah, or Virginia (volu ntary standards) in its calculation. 71 American Council for an Energy-Efficient Economy, State Energy Efficiency Resource Standards (EERS) (2014), available at http://aceee.org/files/pdf/policy-brief/eers-04-201 4.pdf. 72 American Council for an Energy-Efficient Economy, The 2013 State Energy Efficiency Scorecard , at 17 (Nov. 2013), available at http://aceee.org/sites/default/files/publications/r esearchreport s/e13k.pdf.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 81 of 854 intensity of power generation, and ensuring a relia ble supply of power at a reasonable cost. 2. Fossil Fuel- Firedfired EGUs Regulated by Thisthis Action, Generally Natural gas-fired EGUs typically use one of two technologies: NGCC or simple cycle combustion turbi nes. NGCC units first generate power from a combustion turbin e (the combustion cycle). The unused heat from the combust ion turbine is then routed to a heat recovery steam generator ( HRSG) that generates steam , which is then used to produce power using a steam turbine (the steam cycle). Combining these ge neration cycles increases the overall efficiency of the syst em. Simple cycle combustion turbines use a single combustion t urbine to produce electricity (i.e., there is no heat recover y or steam cycle ). The power output from these simple cycle combust ion turbines can be easily ramped up and down making th em ideal for “peaking” operations. Coal-fired utility boilers are primarily either pul verized coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is crushed (pulverized) into a powder in o rder to increase its surface area. The coal powder is then blown into a boiler and burned. In a coal-fired boiler using FB combustion, the coal is burned in a layer of heated particles s uspended in flowing air.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 82 of 854 Power can also be generated using gasification tech nology. An IGCC unit gasifies coal or petroleum coke to for m a synthetic

gas ( or syngas ) composed of carbon monoxide (CO) and hydrogen , (H 2 ), which can be combusted in a combined cycle system to generate power. 3. Technological Developments and Costs Natural gas prices have decreased dramatically and generally stabilized in recent years , as new drilling techniques have brought additional supply to the marketplace a nd greatly increased the domestic resource base. As a result, natural gas prices are expected to be competitive for the fores eeable

future , and EIA modeling and utility announcements confirm that utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. On average, as d iscussed below, the cost of generation from a new natural-ga s fired power plant (a NGCC unit) is expected to be significantly lower than the cost of generation from a new coal-fired power plant. 73 Other drivers that may influence decisions to build new power plants are increases in renewable energy supp lies, often due to state and federal energy policies. As previo usly discussed, many states have adopted RPS, which requ ire a certain

73 Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 20112015 http://www.eia.gov/forecasts/aeo/electricity_genera tion.html.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 83 of 854 portion of electricity to come from renewable energ y sources such as solar or wind. The federal government has a lso adoptedoffered incentives forto encourage further deployment of

other forms of electric generation fromincluding renewable energy sources and loan guarantees for new nuclear power plants. Reflecting these factors, the EIA projections from the last several years show that natural gas is likely to be the most widely-used fossil fuel for new construction of ele ctric generating capacity through 2020, along with renewa ble energy, nuclear power, and a limited amount of coal with CC S. 74 While EIA data shows that natural gas is likely to be the most widely-used fossil fuel for new construction o f electric generating capacity through 20202030 , a few coal-fired units still remain as viable projects at various advanced stages of construction and development. One new coal facility that has essentially completed construction, Southern Compan y's Kemper County Energy Facility, deploys IGCC with partial C CS. Additionally, two other projectsanother project , Summit Power's Texas Clean Energy Project (TCEP ) and the Hydrogen Energy California Project (HECA) – both of), which will deploy IGCC

74 http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pd f; http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf ;http://prod-http-80-800498448.us-east1.elb.amazonaws.com/w/images/6/6d/0383%282011%29.pd f.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 84 of 854 with CCS – continue, continues as a viable projectsproject

. 75 The EIA modeling projects that coal-fired power generat ion will remain the single largest portion of the electricit y sector beyond 2030. The EIA modeling also projects that fe w, if any, new coal-fired EGUs wouldwill be built in this decade and that those that are built wouldwill have CCS. 76 Continued progress on these projects is consistent with the EIA modeling that suggests that a small number of coal-fired power plants may be constructed. The primary reasons for this rate of c urrent and projected future development of new coal projects i nclude highly competitive natural gas prices, lower electricity d emand growth, and increases in the supply of renewable energy. We recognize, however, that a variety of factors may come into pl ay in a decision to build new power generation , and we want to ensure

that there are standards in place to make sure that what ever fuel is burnedutilized is done so in a way that minimizes CO 2 emissions and continues to encourage the development of

75 “Odessa coal-to-gas power plant to break ground th is year”, Houston Chronicle (April 1, 2015). 76 This projection is for business as usual and does not account for the proposed or final CO 2 emission standard. Even in its sensitivity analysis that assumes higher natural ga s prices and electricity demand, EIA does not project any additi onal coal

fired power plants beyond its reference case until 2023, in a case where power companies assume no GHGs emission limitations, and until 2024 in a case where power companies do a ssume GHGs emission limitations.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 85 of 854 innovative technologies into the future , as Congress intended with CAA section 111. 77 4. Energy Sector Modeling Various energy sector modeling efforts, including projections from the EIA and the EPA, forecast tren ds in new power plant construction and utilization of existin g power plants that are consistent with the above-described technological developments and costs. The EIA’s ann ual report, the AEO, forecasts the structure of and developments in the power sector. These reports are based on economic m odeling that reflects existing policy and regulations, such as s tate RPS programs and federal tax credits for renewables. 78 The current report, AEO 2015 79 ,: (i) shows that a modest amount of coal-fired power plants that are currently under construction are expected to begin operation in the next several years (refer red to as “planned”); and (ii) projects in the reference case 80 , that a very small amount of new (“unplanned”) conventional coal-fired

77 These sources received federal assistance under EP Act 2005. See Section III.H.3.g below. However, none of the constraints in that Act affect the discussion in the text above, s ince that discussion does not relate to technology use or emi ssions reduction by these sources. 78 http://www.eia.gov/forecasts/aeo/chapter_legs_regs .cfm. 79 Energy Information Administration’s Annual Energy Outlook for 2015, Final Release available at http://www.eia.gov/forecasts/aeo/index.cfm. 80 EIA’s reference case projections are the result of its baseline assumptions for economic growth, fuel supp ly, technology, and other key inputs.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 86 of 854 capacity, with CCS, will come online after 2012 , and through 2037 in response to Federalfederal and Statestate incentives. According to the AEO 2015, the vast majority of new generating capacity during this period will be either natural gas-fired or

renewable sources . Similarly, the EIA projections from the last several years show that natural gas is likely to be the most widely-used fossil fuel for new construction of ele ctric generating capacity through 20202030

. 81 Specifically, the AEO 2015 projects the need for 28.430.3 GW of additional base load or intermediate load gen eration capacity through 2020 (this includes projects that are under development

–-– i.e., being constructed or in advance planning

-

-- and model-projected nuclear, coal, and NGCC projec ts). The vast majority of this new electric capacity (20.4 G W) is already under development (under construction or in advance d planning); it includes about 100 .7 GW of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 14.2 GW of new NGCC capac ity. The EPA believes that most current fossil fuel-fired projec ts are already designed to meet limits consistent with thi s rule (or they have already commenced construction and are th us not impacted by this notice).subject to these final sta ndards). The AEO 2015 also projects an additional 89.9 GW of new base load

81 Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 20132015

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 87 of 854 capacity additions, which are model-projected (unpl anned). This consists of 7.7 GW of new NGCC capacity, 1.2 GW of new geothermal capacity, 0.7 GW of new hydroelectric ca pacity, and 0.3 GW of new coal equipped with CCS (incentivized with some government funding). Therefore, the AEO 2015 projec tion suggests

that this final rule would only impact small amounts of the new

power generatinggeneration capacity added through 2020 , all of which is expected to already meet the final emissions standards without incurring further control costs. In AEO 2015, thisThis is also true during the period from 2020 through 20 30, where new model-projected (unplanned) intermediate and base l oad capacity is expected to be compliant with the standardstandards without incurring further control costs (i.e., an additiona l 31.3 GW of NGCC and no additional coal, for a total, from 2015 through 2030, of 39 GW of NGCC and 0.3 GW of coal with CCS)

. Under the EIA projections, existing coal-fired gene ration will remain an important part of the mix for power generation. Modeling from both the EIA and the EPA predictproject that coalfired generation will remain the largest single sou rce of electricity in the U.S. through 2040. Specifically, in the EIA’s AEO 2015, coal will supply approximately 40 percent of all electricity in the electric power sector in both 20 20 and 2025. The EPA modeling using the Integrated Planning Mode l (IPM), a detailed power sector model that the EPA uses to support power*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 88 of 854 sector regulations, also shows limited future const ruction of new coal-fired power plants under the base case. 82 The EPA’s projections from IPM can be found in the RIA. 5. Integrated Resource Plans The trends in the power sector described above are also apparent in publicly available long-term resource p lans, known as integrated resource plans (IRPs). The EPA has reviewed publicly available IRPs from a range of companies (e.g., varying in size, location, curr ent fuel mix), and these plans are generally consistent with both EIA and EPA modeling projections. 83 These IRPs indicate that companies are focused on demand-side management programs to l ower future electricity demand and are mostly reliant on a mix of new natural gas-fired generation and renewable energy t o meet increased load demand and to replace retired genera tion capacity. Notwithstanding this clear trend towards natural ga s-fired generation and renewables, many of the IRPs highlig ht the value of fuel diversity and include options to diversify new generation capacity beyond natural gas and renewabl e energy.

82 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation. 83 Technical Support Document - “Review of Electric U tility Integrated Resource Plans” (May 2015), available in the rulemaking docket EPA-HQ-OAR-2013-0495.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 89 of 854 Several IRPs indicate that companies are considerin g new nuclear generation, including either traditional nuclear po wer plants or small modular reactors, and a smaller number are co nsidering new coal-fired generation capacity with and without CCS technology. Based onBased on public comments and on the informa tion contained in these IRPs, the EPA acknowledges that a small number of new coal-fired power plants may be built in the near future. While this outcome would be contrary to the economic modeling predictions, the agency understands that e conomic modeling may not fully reflect the range of factors that a particular company may consider when evaluating new generation options, such as fuel diversification. Further , it is possible that some of this potential new coal-fired construc tion may occur because developers are able to design project s with specific business plans, such as the cogeneration o f chemicals, which allow the source to provide competitively pri ced electricity in specific geographic regions. D. Statutory Background The U.S. Supreme Court ruled , in Massachusetts v. EPA , that greenhouse gases ( GHGs ) 84 meet the definition of “air pollutant”

84 The EPA’s 2009 endangerment finding defines the ai r pollution which may endanger public health and welfare as the well-mixed aggregate group of the following gases: CO 2 , methane (CH 4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF 6 ), hydrofluorocarbons (HFCs), and perfluorocarbons (PF Cs).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 90 of 854 in the CAA, 85 and premised its decision in AEP v. Connecticut , 86 that the CAA displaced any federal common law right to compel reductions in CO 2 emissions from fossil fuel-fired power plants , on its view that CAA section 111 applies to GHG emi ssions. CAA section 111 authorizes and directs the EPA to p rescribe new source performance standards (NSPS) applicable to certain new stationary sources (including newly constructed , modified and reconstructed sources). 87 As a preliminary step to regulation, the EPA must list categories of station ary sources that the Administrator, in his or her judgment, fin ds “cause[], or contribute[] significantly to, air pollution whi ch may reasonably be anticipated to endanger public health or welfare.” The EPA has listed and regulated more than 60 stati onary source categories under CAA section 111. 88 The EPA listed the two source categories at issue here in the 1970s : The EPA listed - listing fossil fuel-fired electric steam generating units i n 1971 ; 89 and listing combustion turbines in 1977. 90 Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new

85 549 U.S. 497, 520 (2007). 86 131 S.Ct. 2527, 2537-38 (2011). 87 CAA section 111(b)(1)(A). 88 See generally 40 CFR part 60, subparts D-MMMM. 89 36 FR 5931 (March 31, 1971). 90 42 FR 53657 (October 3, 1977).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 91 of 854 sources” in the category. 91 A “new source” is “any stationary source, the construction or modification of which i s commenced after,” in general, final standards applicable to t hat source are promulgated or, if earlier, proposed. 92 A modification is “any physical change ... or change in the method of operation ... which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” 93 The EPA, through regulations, has determined that certain types of c hanges are exempt from consideration as a modification. 94 The NSPS general provisions (40 CFR part 60, subpar t A) provide that an existing source is considered to be a new source if it undertakes a “reconstruction,” which is the r eplacement of components of an existing facility to an extent tha t (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to co nstruct a comparable entirely new facility, and (2) it is tec hnologically and economically feasible to meet the applicable st andards. 95

91 CAA section 111(b)(1)(B). 92 CAA section 111(a)(2). 93 CAA section 111(a)(4). CAA section 111(a)(4); See also 40 CFR 60.14 concerning what constitutes a modification, h ow to determine the emission rate, how to determine an em ission increase, and specific actions that are not, by the mselves, considered modifications. 94 40 CFR 60.2, 60.14(e). 95 40 CFR 60.15.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 92 of 854 CAA section 111(a)(1) defines a “standard of perfor mance” as “a standard for emissions of air pollutants whic h reflects the degree of emission limitation achievable throug h the application of the best system of emission reductio n which (taking into account the cost of achieving such red uction and

any nonairnon-air quality health and environmental impact and energy requirements) the Administrator determines h as been adequately demonstrated.” This definition makes cle ar that the standard of performance must be based on “the best system of emission reduction

.... . . adequately demonstrated” (BSER). The standard that the EPA develops, reflecting the performance of the BSER, is commonly a numeric emis sion limit, expressed as a numeric performance level whichthat can either be normalized to a rate of output or input (e.g .., tons of pollution per amount of product produced – a so-cal led ratebased standard), or expressed as a numeric limit on mass of pollutant whichthat may be emitted (e.g., 100 ug/m 3 – parts per billion). Generally, the EPA does not prescribe a p articular technological system that must be used to comply wi th a standard of performance. 96 Rather, sources generally may select any measure or combination of measures that will achiev e the

96 CAA sectionssection 111 (b)(5) and (h).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 93 of 854 emissions level of the standard. 97 In establishing standards of performance, the EPA has significant discretion to create subcategories based on source type, class , or size. 98 The text and legislative history of CAA section 111 , as well as relevant court decisions , identify the factors forthat

the EPA is to consider in making a BSER determination. The system of emission reduction must be technically fe asible, the costs of the system must be reasonable, and the emi ssion standard that the EPA promulgates based on the syst em of emission reduction must be achievable. In addition, in identifying a BSER, the EPA must consider the amount of emissions reductions thatattributable to the system would generate, along with considerations concerning ener gy , and must also consider non-air quality pollutantshealth and environmental impacts and energy requirements . The case law addressing CAA section 111 makes it clear that the EPA has discret ion in weighing costs, amount of emission reductions, ener gy requirements, and impacts of non-air quality pollut ants, and that as a result, the EPA may weigh them differently for different types of sources or air pollutants. We no te that under the case law of the D.C. Circuit, another factor is relevant for

97 CAA section 111(b)(5). 98 CAA section 111(b)(2); see also Lignite Energy Council v. EPA , 198 F. 3d 930, 933 (D.C. Cir. 1999).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 94 of 854 the BSER determination: whether the standard would effectively promote further deployment or development of advanc ed technologies. Within the constraints just described , the EPA has discretion in identifying the BSER and the resultin g emission

standard. See generally Section III.H below. For more than four decades, the EPA has used its au thority under CAA section 111 to set cost-effective emissio n standards thatwhich ensure that newly constructed, reconstructed , and modified stationary sources use the best performing technologies to limit emissions of harmful air pollutants. In th is final action, the EPA is following the same well-establis hed interpretation and application of the law under CAA section 111 to address GHG emissions from newly constructed, re constructed , and modified fossil fuel-fired power plants. For ea ch of the standards in this final action, the EPA considered a number of alternatives and evaluated them against the statuto ry factors. The BSER for each category of affected sourcesEGUs and the standards of performance based on these BSER are ba sed on that evaluation. E. Regulatory Background In 1971, the EPA initially included fossil fuel-fir ed EGUs (which includes natural gas, petroleum and coal) th at use steamgenerating boilers in a category that it listed und er CAA*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 95 of 854 section 111(b)(1)(A), 99 and promulgated the first set of standards of performance for sources in that catego ry, which it codified in subpart D. 100 In 1977, the EPA initially included fossil fuel-fired combustion turbines in a category that the EPA listed under CAA section 111(b)(1)(A), 101 and the EPA promulgated standards of performance for that source category i n 1979, which the EPA codified in subpart GG. 102 The EPA has revised those regulations, and in some instances, has revised the codifications (that is, the 40 CFR part 60 subparts), several times over the ensuing d ecades. In 1979, the EPA divided subpart D into 3 subparts – D a (“Standards of Performance for Electric Utility Steam Generatin g Units for Which Construction is Commenced After September 18, 1978”), Db (“Standards of Performance for Industrial-Commercia lInstitutional Steam Generating Units”) and Dc (“Sta ndards of Performance for Small Industrial-Commercial-Institu tional Steam Generating Units”) – in order to codify separate re quirements

99 36 FR 5931 (March 31, 1971 )). 100 “Standards of Performance for Fossil-Fuel-Fired St eam Generators for Which Construction Is Commenced Afte r August 17, 1971,” 36 FR 24875 (December 23, 1971) codified at 40 CFR 60.40- 46. 101 42 FR 53657 (October 3, 1977). 102 “Standards of Performance for Electric Utility Ste am Generating Units for Which Construction is Commence d After September 18, 1978,” 44 FR 33580 (June 11, 1979).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 96 of 854 that it established for these subcategories. 103 In 2006, the EPA created subpart KKKK, ”Standards of Performance for Stationary Combustion Turbines,” which applied to certain sour ces previously regulated in subparts Da and GG

. 104 None of these subsequent rulemakings, including the revised codif ications, however, constituted a new listing under CAA sectio n 111(b)(1)(A). The EPA promulgated amendments to subpart Da in 200 6, which included new standards of performance for criteria pollutants for EGUs, but nodid not include specific standards of performance for GHGCO 2 emissions. 105 Petitioners sought judicial review of the rule by the D.C. Circuit , contending, among other issues , that the rule was required to include standards of performance for GHG emissions from EGUs. 106 The January 8, 2014 preamble to the proposed CO 2 standards for new EGUs 107 includes a discussion of the GHG-related litigation of the 200 6 Final Rule as well as other GHG-associated litigation.

103 44 FR 33580 (June 11, 1979 )). 104 71 FR 38497 (July 6, 2006), as amended at 74 FR 11 861 (March 20, 2009). 105 ”Standards of Performance for Electric Utility Ste am Generating Units, Industrial-Commercial-Institution al Steam Generating Units, and Small Industrial-Commercial-I nstitutional Steam Generating Units, Final Rule.” 71 FR 9866 (Fe bruary 27, 2006). 106 State of New York, et al. v. EPA , No. 06–1322

. 107 79 FR 1430 , 1444.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 97 of 854

F. Development ofCarbon Pollution Standards for Fossil FuelFiredfired

Electric Utility Generating Units On April 13, 2012, the EPA initially proposed stand ards under CAA section 111 for newly constructed fossil fuel-fired electric utility steam generating utility steam generating units. 77 FR 22392 (“April 2012 proposal”). The EPA withdrew that proposal (79 FR 1352 (January 8, 2014)), and, on the same day, proposed the standards addressed in this final rule. 79 FR 1430 (“January 2014 proposal”). Specifically, the EPA pr oposed standards under CAA section 111 to limit emissions of CO 2 from newly constructed fossil fuel-fired electric utilit y steam generating units and newly constructed natural gas- fired stationary combustion turbines. In support of the January 2014 proposal, on Februar y 26, 2014, the EPA published a notice of data availabili ty (NODA) (79 FR 10750). Through the NODA and thean associated technical support document, Effect of EPAct05 on Best System of Emission Reduction for New Power Plants , the EPA solicited comment on its interpretation of the provisions in the Energy Poli cy Act of 2005 (EPAct05 )), 108 , including how the provisions may affect the

108 See Section III.H.3.g below. The Energy Policy Act of 2005 (EPAct05) was signed into law by President George W . Bush on August 8, 2005. EPAct05 was intended to address ene rgy production in the United States, including: (1) ene rgy efficiency; (2) renewable energy; (3) oil and gas; (4) coal; (5)*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 98 of 854 rationale for the EPA’s proposed determination that partial CCS is the best system of emission reduction adequately demonstrated for fossil fuel-fired electric utility steam genera ting units. On June 18, 2014, the EPA proposed standards of per formance to limit emissions of CO 2 from modified and reconstructed fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines (79 FR 3495934960 ; June 2014 proposal). Specifically, the EPA proposed stan dards of performance for: (1) modified fossil fuel-fired ele ctric utility steam generating units, (2) modified natural gas-fi red stationary combustion turbines, (3) reconstructed f ossil fuelfired electric utility steam generating units, and (4) reconstructed natural gas-fired stationary combusti on turbines. G. Stakeholder Engagement and Public Comments on th e Proposals 1. Stakeholder Engagement The EPA has engaged extensively with a broad range of stakeholders and the general public regarding clima te change, carbon pollution from power plants, and carbon poll ution reduction opportunities. These stakeholders include d industry and electric utility representatives, state and loc al officials,

Tribal energy; (6) nuclear matters and security; (7 ) vehicles and motor fuels, including ethanol; (8) hydrogen; ( 9) electricity; (10) energy tax incentives; (11) hydro power and geothermal energy; and (12) climate change technolo gy. www2.epa.gov/laws-regulations/summary-energy-policy -act .*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 99 of 854 tribal officials, labor unions, non-governmental or ganizations and many others. In February and March 2011, early in the process of developing carbon pollution standards for new power plants, the EPA held five listening sessions to obtain informat ion and input from key stakeholders and the public. Each of the f ive sessions had a particular target audience: the electric powe r industry, environmental and environmental justice organizatio ns, states and tribes, coalition groups, and the petroleum ref inery industry. The EPA conducted subsequent outreach prior to the June 2014 proposals of standards for modified and recons tructed EGUs and emission guidelines for existing EGUs, as well as during the public comment periods for the proposals. Although this stakeholder outreach was primarily framed around th e GHG emission guidelines for existing EGUs, the outreach encompassed issues relevant to this rulemaking and provided an opportunity for the EPA to better understand previous state and stakeholder experience with reducing CO 2 emissions in the power sector. In addition to 11 public listening sessions, the EPA h eld hundreds of meetings with individual stakeholder groups, and meetings that brought together a variety of stakeholders to discuss a wide range of issues related to the electricity sec tor and regulation of GHGs under the CAA. The agency met wi th electric*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 100 of 854 utility associations and electricity grid operators . Agency officials engaged with labor unions and with leader s representing large and small industries , many of which have been utilities and industry representatives directly rel ated to the electricity sector.. The agency also met with energy industries , such as coal and natural gas interests, as well as with representatives of energy - intensive industries, such as the iron and steel , and aluminum industries, to helpbetter understand the potential concerns of large industri al purchasers of electricity. In addition, the agency met with co mpanies that offer new technology to prevent or reduce carbon po llution. The agency provided and encouraged multiple opportuniti es for engagement with state, local, tribal, and regional environmental and energy agencies. The EPA also met with represen tatives of environmental justice organizations, environmental groups, and public health professionals, public health organiza tions, religious organizations , and other community stakeholders

. The EPA received more than 2.5 million comments sub mitted in response to the original April 2012 proposal for newly constructed fossil fuel-fired EGUs. Because the ori ginal proposal was withdrawn, the EPA instructed commente rs that wanted their comments on the April 2012 proposal to be considered in connection with the January 2014 prop osal to submit new comments to the EPA or to re-submit thei r previous*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 101 of 854 comments. We received more comments in response to the January 2014 proposal, as discussed in the section below. The EPA has given stakeholder input provided prior to the proposals, as well as during the public comment per iods for each proposal, careful consideration during the developm ent of this rulemaking and, as a result, it includes elements t hat are responsive to many stakeholder concerns and that en hance the rule. This preamble and the Response - to - Comments (RTC) document summarize and provide ourthe agency’s responses to the comments received by the agency

. 2. Comments on the January 2014 Proposal for Newly Constructed Fossil Fuel-fired EGUs Upon publication of the January 8, 2014 proposal fo r newly constructed fossil fuel-fired EGUs, the EPA offeredprovided a 60-day public comment period. On March 6, 2014, in order to provide the public additional time to submit commen ts and supporting information, the EPA extended the commen t period by 60 days, to May 9, 2014, giving stakeholders over 1 20 days to review, and comment upon, the January 2014 proposal , as well as the NODA. A public hearing was held on February 6, 2014, with 159 speakers presenting testimony. The EPA received more than 2 million comments on the proposed standards for newly constructed fossil fue l-fired EGUs from a range of stakeholders that included industry and electric*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 102 of 854 utility representatives, trade groups, equipment ma nufacturers, state and local government officials, academia, env ironmental organizations, and various interest groups. The age ncy received comments on a range of topics, including the determ ination that a new highly-efficient steam generating EGU impleme nting partial

CCS was the BSER for newly constructed fossil fuel-fired steam generating EGUssuch sources , the level of the CO 2 standard based

on implementation of partial CCS, the criteria that definesdefine which newly constructed natural gas-fired stationary combustion turbines will be subject to s tandards, the establishment of subcategories based on combustion turbine size, and the rule’s potential effects on the Prevention of Significant Deterioration (PSD) preconstruction per mit program

and titleTitle V operating permit program. 3. Comments on the June 2014 Proposal for Modified and Reconstructed Fossil Fuel-fired EGUs Upon publication of the June 18, 2014 proposal for modified and reconstructed fossil fuel-fired EGUs, the EPA o ffered a 120- day public comment period

--- through October 16, 2014. The EPA held public hearings in four locations during the w eek of July 28, 2014. These hearings also addressed the EPA’s June 18, 2014 proposed emission guidelines for existing fossil fu el-fired EGUs (reflecting the connections between the proposed st andards for modified and reconstructed sources and the proposed emission*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 103 of 854 guidelines). A total of 1,322 speakers testified, a nd a further 1,450 attended but did not speak. The speakers were provided the opportunity to present data, views , or arguments concerning one or both proposed actions

. The EPA received over 200 comments on the prop osed standards for modified and reconstructed fossil fue l-fired EGUs from a range of stakeholders similar to those that submitted comments on the January 2014 proposal for newly con structed fossil fuel-fired EGUs (i.e., industry and electric utility representatives, trade groups, equipment manufactur ers, state and local government officials, academia, environme ntal organizations, and various interest groups). The agency received comments on a range of topics, including the method ology for determining unit-specific CO 2 standards for modified steam generating units and the use of supercritical boile r conditions as the basis for the CO 2 standards for certain reconstructed steam generating units. Many of the comments regard ing modified and reconstructed natural gas-fired stationary comb ustion turbines are similar to the comments regarding newl y constructed combustion turbines described above (e.g., applicab ility criteria and subcategories based on turbine size).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 104 of 854 III. Regulatory Authority, Affected SourcesEGUs and Their Standards, and Legal Requirements In this section, we describe our authority to regu late CO 2 from fossil fuel-fired EGUs. We also describe our d ecision to combine the two existing categories of affected EGU s – steam generators and combustion turbines

--- into a single category of fossil fuel-fired EGUs for purposes of promulgating standards of performance for CO 2 emissions. We also explain that we are codifying all of the requirements in this rule for all new and, modified , and reconstructed affected EGUs in new subpart TTTT of part 60 of Title 40 of the Code of Federal Regulati ons. In addition, we explain which sources are and are not affected by this rule, and the format of these standards. Final ly, we describe the legal requirements for establishing th ese emission

standards. A. Authority to Regulate Carbon Dioxide from Fossil Fuel-fired

EGUs The EPA’s authority for this rule is CAA section 11 1(b)(1). CAA section 111(b)(1)(A) requires the Administrator to establish a list of source categories to be regulated under s ection 111. A category of sources is to be included on the list “if in [the Administrator’s] judgment it causes, or contributes significantly to, air pollution which may reasonabl y be anticipated to endanger public health and welfare.” This*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 105 of 854 determination is commonly referred to as an “endang erment finding” and that phrase encompasses both the “caus es or contributes significantly” component and the “endan ger public health and welfare” component of the determination. Then, for the source categories listed under section 111(b)(1 )(A), the Administrator promulgates, under section 111(b)(1)( B), regulations “standards of performance for new sources within such category.” In this rule, the EPA is establishing standards und er section 111(b)(1)(B) for source categories that wereit has previously listed and regulated for other pollutant s and which now are being regulated for an additional pollutant . Because of this, there are two aspects of section 111(b)(1) th at warrant particular discussion. First, because the EPA is not listing a new source category in this rule, the EPA is not required to make a new endangerment finding with regard to affected EGUs in order to es tablish standards of performance for the CO 2 emissions from those sources. Under the plain language of CAA section 11 1(b)(1)(A), an endangerment finding is required only to list a source category. Further, though the endangerment finding is based on determinations as to the health or welfare impacts of the pollution to which the source category’s pollutants contribute, and as to the significance of the amount of such co ntribution,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 106 of 854 the statute is clear that the endangerment finding is made with respect to the source category; section 111(b)(1)(A ) does not provide that an endangerment finding is made as to specific pollutants. This contrasts with other CAA provision s that do require the EPA to make endangerment findings for e ach particular pollutant that the EPA regulates under t hose provisions. E.g., CAA sections 202(a)(1), 211(c)(1), 231(a)(2)(AE.g., CAA sections 202(a)(1), 211(c)(1), and 231(a)(2)(A); see also American Electric Power Co. Inc., v. Connecticut , 131 S. Ct. 2527, 2539 (2011) (“[T]he Clean Air Ac t directs the EPA to establish emissions standards fo r categories of stationary sources that, ‘in [the Administrator' s] judgment,’ ‘caus[e], or contribut[e] significantly to, air pol lution which may reasonably be anticipated to endanger public he alth or welfare.’ § 7411(b)(1)(A).”) (emphasis added ). Second, once a source category is listed, the CAA d oes not specify what pollutants should be the subject of st andards from that source category. The statute, in section 111(b )(1)(B), simply directs the EPA to propose and then promulga te regulations “establishing Federalfederal standards of performance for new sources within such category.” In the absence of specific direction or enumerated criteri a in the statute concerning what pollutants from a given sou rce category should be the subject of standardstandards , it is appropriate*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 107 of 854

for the EPA to exercise its authority to adopt a reasonabl e interpretation of this provision. Chevron U.S.A. Inc. v. NRDC , 467 U.S. 837, 843-44 (1984). 109 The EPA has previously interpreted this provision a s granting it the discretion to determine which pollu tants should be regulated. See Standards of Performance for Petroleum Refineries, 73 Fed. Reg. 35838 , 35858 (col. 3)( ( June 24, 2008 )() ( concluding that the statute provides “the Administrator with significant flexibility in determining which p ollutants are appropriate for regulation under section 111(b)(1)( B)” and citing cases). Further, in directing the Administra tor to propose and promulgate regulations under section 11 1(b)(1)(B), Congress provided that the Administrator should tak e comment and then finalize the standards with such modifications “as he deems appropriate.” The D.C. Circuit has considered similar statutory phrasing from CAA section 231(a)(3) and concluded t hat “[t]his delegation of authority is both explicit and extrao rdinarily

broad.” National Assoc. of Clean Air Agencies v. EPA , 489 F.3d 1221, 1229 (D.C. Cir. 2007).

109 In Chevron , the U.S. Supreme Court held that an agency must, at Step 1, determine whether Congress’s intent as t o the specific matter at issue is clear, and, if so, the agency must give effect to that intent. If Congressional intent is not clear, then, at Step 2, the agency has discretion t o fashion an interpretation that is a reasonable construction of the statute.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 108 of 854 In exercising its discretion with respect to which pollutants are appropriate for regulation under sec tion 111(b)(1)(B), the EPA has in the past provided a ra tional basis for its decisions. See National Lime Assoc. v. EPA , 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980 )() ( court discussed, but did not review, the EPA’s reasons for not promulgating stan dards for oxides of nitrogen ( NO X , ), sulfur dioxide ( SO 2 ) and CO from lime plants ”);); Standards of Performance for Petroleum Refineries, 73 Fed. Reg. at 35859-60 (June 24, 2008 )() ( providing reasons why the EPA was not promulgating GHG standards for petroleum refineries as part of that rule). Though these prev ious examples involved the EPA providing a rational basis for not setting standards for a given pollutant, a similar approach is appropriate where the EPA determines that it should set a standard for an additional pollutant for a source c ategory that was previously listed and regulated for other pollu tants. In this rulemaking, the EPA has a rational basis fo r concluding that emissions of CO 2 from fossil fuel -fired power plants, which are the major U.S. source of greenhouse gasGHG air pollution, meritsmerit regulation under CAA section 111. As noted, in 2009, the EPA made a finding that GHG air pollution may reasonably be anticipated to endanger public he alth or welfare, and in 2010, the EPA denied petitions to r econsider that finding. The EPA extensively reviewed the avai lable science*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 109 of 854 concerning GHG pollution and its impacts in taking those actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit upheld the finding and the denial of petitions to reconsider. 110 In addition, assessments from the NRC, the IPCC, an d other organizations published after 2010 lend further cre dence to the validity of the Endangerment Finding. As discussed below, noNo information that commenters have presented or that the EPA has reviewed provides a basis for rescinding that findingreaching a different conclusion . Indeed, current and evolving science discussed in detail in Section II.A of this preambl e is confirming and enhancing our understanding of the n ear- and longer-term impacts emissions of CO 2 are having on Earth’s climate and the adverse public health, welfare, and economic consequences that are occurring and are projected t o occur as a result. Moreover, the high level of GHG emissions from the fossil

fuel -fired EGUs makes clear that it is rational for the EPA to regulate GHG emissions from this sector. EGUs emit almost onethird of all U.S. GHGs and comprise by far the larg est stationary source category of GHG emissions; indeed , as noted above, the CO 2 emissions from fossil fuel-fired EGUs are almost three times as much as the emissions from the next ten source

110 Coalition for Responsible Regulation v. EPA , 684 F.3d 102, 119-126 (D.C. Circuit 2012).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 110 of 854 categories combined. Further, the CO 2 emissions from even a single new coal-fired power plant may amount to mil lions of tons each year. See, e.g., Section V.K below (noting that even the difference in CO 2 emissions between a highly efficient SCPC and the same unit meeting today’s standard of performan ce can amount to hundreds of thousands of tons each year). These facts provide a rational basis for regulating CO 2 emissions from affected EGUs. Some commenters have argued that the EPA is require d to make a new endangerment finding before it may regul ate CO 2 from

EGUs. We disagree, for the reasons discussed above. Moreo ver, as discussed in the January 2014 proposal, 111 even if CAA section

111 is interpreted to require thatrequired the EPA to make endangerment and cause-or-contribute significantly findings as prerequisites for this rulemaking, then, so far as the “CO 2 endangers public health and welfare” component of an endangerment finding is concerned, the fact that the EPA has recently made an endangerment finding for GHGs shou ld suffice, and even if not, the information and conclusions described above should be considered to constitute the requisite en dangerment finding. Similarly, so far as a cause-or-contribute significantly finding is concerned, the information and conclusions described above should be considered to constitute

111 79 FR 1430, 1455-56 (January 8, 2014).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 111 of 854 the requisite finding. The EPA’s rational basis for regulating

GHGsCO 2 under CAA section 111 is based primarily on the ana lysis and conclusions in the EPA’s 2009 Endangerment Find ing and 2010 denial of petitions to reconsider that Finding, cou pled with the subsequent assessments from the IPCC and NRC that d escribe scientific developments since those EPA actions. In addition, we have reviewed comments presenting other scientific information to determine whether that information has any meani ngful impact on our analysis and conclusions. More specifically, our approach here – reflected in the information and conclusions described above – is su bstantially similar to that reflected in the 2009 Endangerment Finding and the 2010 denial of petitions to reconsider. The D.C . Circuit upheld that approach in Coalition for Responsible Regulation v.

EPA , 684 F.3d 102, 117-123 (D.C. Cir. 2012). Accordingly, that approach would support an endangerment finding for this rulemaking.2012) (noting, among other things, the “ substantial ... body of scientific evidence marshaled by EPA in sup port of the Endangerment Finding” (id. at 120); the “substantia l record evidence that anthropogenic emissions of greenhouse gases ‘very likely’ caused warming of the climate over the last several decades” (id. at 121); “substantial scientific evid ence ... that anthropogenically induced climate change threatens both public health and public welfare . . . [through] extreme w eather*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 112 of 854 events, changes in air quality, increases in food- and waterborne pathogens, and increases in temperatures” (id .); and “substantial evidence ... that the warming resulting from the greenhouse gas emissions could be expected to creat e risks to water resources and in general to coastal areas . . . .” (id.)). The facts, unfortunately, have only grown stronger and the potential adverse consequences to public health and the environment more dire in the interim. Accordingly, that approach would support an endangerment finding for this rulemaking. 112

112 Nor does the EPA consider the cost of potential st andards of performance in making this Finding. Like the Endang erment Finding under section 202(a) at issue in State of Massachusetts v. EPA , 549 U.S. 497 (2007) the pertinent issue is a scie ntific inquiry as to whether an endangerment to public hea lth or welfare from the relevant air pollution may reasona bly be anticipated. Where, as here, the scientific inquiry conducted by the EPA indicates that these statutory criteria are met, the Administrator does not have discretion to decline t o make a positive endangerment finding to serve other policy grounds. Id. at 532-35. In this regard, an endangerment finding is analogous to setting national ambient air quality standards u nder section 109(b), which similarly call on the Administrator t o set standards that in her “judgment” are “requisite to protect the public health”. The EPA is not permitted to conside r potential costs of implementation in setting these standards. Whitman v. American Trucking Assn’s , 531 U.S. 457, 466 (2001); see also Michigan v. EPA , U.S. (no. 14-46, June 29, 2015) slip op. pp. 10-11 (reiterating Whitman holding). The EPA notes further that section 111(b)(1) contains no terms such as “neces sary and appropriate” which could suggest (or, in some conte xts, require) that costs may be considered as part of the finding . Compare CAA section 111(n)(1)(A); see State of Michigan , slip op. pp. 7-8. The EPA, of course, must consider costs in determin ing whether a best system of emission reduction is adequately dem onstrated and*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 113 of 854

Likewise, if the EPA were required to make a cause- orcontribute-significantly finding for CO 2 emissions from the fossil fuel-fired EGUs , as a prerequisite to regulating such emissions under CAA section 111, the same facts tha t support our rational basis determination would support such a f inding. In particular, as noted, combustion turbines alone emi t 401 million metric tonnes per year, which is more than any othe r source category except for steam generators, and steam gen erators emit 1,627 million metric tonnes per year.As shown in Ta bles 3 and 4 in this preamble, fossil fuel-fired EGUs are very l arge emitters

of CO 2 . All told, these fossil fuel-fired EGUs emit almost onethird of all U.S. GHG emissions, and are responsibl e for almost three times as much as the emissions from the next ten stationary source categories combined. The CO 2 emissions from even a single new coal-fired power plant may amount to millions of tons each year, and the CO 2 emissions from even a single NGCC unit may amount to one million or more tons per yea r. It is not

so can form the basis for a section 111(b) standard of performance, and the EPA has carefully considered c osts here and found them to be reasonable. See section V. H. and I. below. The EPA also has found that the rule’s quantifiable benefits exceed regulatory costs under a range of assumption s were new capacity to be built. RIA chapter 5 and section XII I.G below. Accordingly, this endangerment finding would be jus tified if (against our view) it is both required, and (again, against our view) costs are to be considered as part of the fin ding.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 114 of 854 necessary in this rulemaking for the EPA to decide whether it must identify a specific threshold for the amount o f emissions from a source category that constitutes a significa nt contribution; under any reasonable threshold or def inition, the emissions from combustion turbines and steam genera tors are a significant contribution. Indeed, these emissions far exceed in magnitude the emissions from motor vehicles, which have already been held to contribute to the endangerment. See Coalition for Responsible Regulation , 684 F. 3d at 121 (“substantial evidence” supports the EPA’s determination “that motor-vehicl e emissions of greenhouse gases contribute to climate change an d thus to the endangerment of public health and welfare”). 113

113 The “air pollution” defined in the Endangerment Fi nding is the atmospheric mix of six long-lived and directly emitted greenhouse gases: carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PF Cs), and sulfur hexafluoride (SF 6 ). See 74 FR 66496 at 66497. The standards of performance adopted in the present rul emaking address only one component of this air pollution: C O 2 . This is reasonable, given that CO 2 is the air pollutant emitted in the largest volume by the source category, and which is (necessarily) emitted by every affected EGU. There is, of course, no requirement that standards of performanc e address each component of the air pollution which endangers . Section 111(b)(1)(A) requires the EPA to establish “standar ds of performance” for listed source categories, and the definition of “standard of performance” in section 111 (a)(1) doe s not specify which air pollutants must be controlled. See also S ection III.G below explaining that CH 4 and N 2 O emissions represent less than 1 percent of total estimated GHG emissions (as CO 2 e) from fossil fuel-fired electric power generating units.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 115 of 854 B. Treatment of Categories and Codification in the Code of Federal Regulations As discussed in the January 2014 proposal of carbon pollution standards for newly constructed EGUs (79 FR 1430) and above, in 1971 the EPA listed fossil fuel-fired ste am generating boilers as a new category subject to CAA section 11 1 rulemaking, and in 1979 the EPA listed fossil fuel-fired combus tion turbines as a new category subject to the CAA section 111 ru lemaking. In the ensuing years, the EPA has promulgated standard s of performance for the two categories and codified tho se standards, at various times, in 40 CFR part 60, subparts D, Da , GG, and

KKKK. In the January 2014 proposal of carbon pollution st andards for newly constructed EGUs (79 FR 1430) and the Jun e 2014 proposal of carbon pollution standards for modified and reconstructed EGUs (79 FR 34960), the EPA proposed separate standards of performance for new, modified, and rec onstructed sources in the two categories. The EPA took comment on combining the two categories into a single category solely fo r purposes of

the CO 2 emissions from new, modified, and reconstructed af fected EGUs. In addition, the EPA proposed codifying the s tandards of performance in the same Da and KKKK subparts that c urrently contain the standards of performance for other poll utants from those sources addressed in the NSPS program, but co -proposed*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 116 of 854 codifying all the proposed standards of performance for CO 2 emissions in a new 40 CFR part 60 , subpart TTTT. In this rule, the EPA is combining the steam genera tor and combustion turbine categories into a single categor y of fossil fuel-fired electricity generating units for purpose s of promulgating standards of performance for GHG emiss ions. Combining the two categories is reasonable because they both provide the same product: electricity services. Mor eover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for exi sting sources that accompanies this rule. In addition, many of th e monitoring, reporting, and verification requirements are the sa me for both source categories, and, as discussed next, we are c odifying all requirements in a single new subpart of the regulat ions; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this r ule, we are not combining the two categories for purposes of st andards of performance for other air pollutants. Because these two source categories are pre-existin g listed source categories and the EPA will not be subjecting any additional sources in the categories to CAA regulat ion for the first time, the combination of these two categories is not considered a new source category subject to the lis ting requirements of CAA section 111(b)(1)(A). As a result, this*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 117 of 854 final rule does not list a new category under CAA s ection 111(a)(1)(A), nor does this final rule revise eithe r of the two source categories. Thus, the EPA is not required to make a new endangerment and contribution finding thatfor the combination of the two categories causes or, 114 although as discussed in the previous section, the evidence strongly supports su ch findings. Thus, the EPA has found, in the alternative, that t his category

of sources contributes significantly to air pollution which m ay be reasonably be anticipated to endanger public health orand

welfare. As discussed above in the regulatory background of CAA section 111(b) actions on EGUs, there are several s ubparts in the code of federal regulations addressing EGUs (i. e., D, Da, GG, KKKK). This final action codifies all of the re quirements promulgated in this final rule for the affected EGU s in a new subpart TTTT of 40 CFR part 60 and includes all GHG emission standards for the affected sources – electric utili ty steam generating units, as well as natural gas-fired stat ionary combustion turbines -- in that newly created subpar t. Combining the emission standards for affected sources into a new subpart

114 See, e.g., American Trucking Assn’s v. EPA , 175 F.3d 1027, 1055, rev’d on other grounds sub. nom. Whitman v. Am. Trucking Assn’s , 531.U.S. 457 (because fine particulate matter (PM 2.5 ) was already included as a sub-set of the listed polluta nt particulate matter, it was not a new pollutant nece ssitating a new listing).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 118 of 854 TTTT is appropriate because many of the same requir ements, including monitoring, reporting, and verification r equirements, apply to all of the affected EGUs; and is consisten t with the approach being taken for final existing source emis sion guidelines, in which we codify all of the requireme nts for the affected EGUs in new subpart UUUU of 40 CFR part 60

. C. Affected Units We generally refer to fossil fuel-fired electric ge nerating units that would be subject to a CAA section 111 em ission standard as “affected” or “covered” sources, units, facilities or simply as EGUs. An EGU is any boiler, integrated gasification combined cycle (IGCC)IGCC unit, or combustion turbine (in either simple cycle or combined cycle configuration) that meets the applicability criteria. Affected sourcesEGUs include EGUsthose that commenced construction after January 8, 2014 , and meet the specified applicability criteria and, for modificat ions and reconstructions, EGUs that commenced those activiti es after June 18, 2014 , and meet the specified applicability criteria. To be considered an EGU , the unit must be: (1) be capable of combusting more than 250 MMBtu/h (260 GJ/h) heat input of fossil fuel ; 115 and (2) serve a generator capable of supplying

115 We refer to the capability to combust 250 MMBtu/h of fossil fuel as the "base load rating criterion." Note that 250 MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 119 of 854 more than 25 MW net to a utility distribution syste m (i.e., for sale to the grid). 116 However, we are not finalizing GHGCO 2 standards for certain EGUs. The EGUs that are not c overed by the standards we are finalizing in this rule include : (1) non-fossil

fuel units subject to a federally enforceable permit tha t limits the use of fossil fuels to 10 percent or less of thetheir heat input capacity on an annual basis; (2) combined hea t and power (CHP) units that are subject to a federally enforceable p ermit limiting annual net - electric sales to no more than the product of theirunit’s design net efficiency times theirmultiplied by its potential electric output , or limiting annual electric sales

to 219,000 MWh or less , whichever is greater ; (3) stationary combustion turbines that are subjectnot physically capable of combusting natural gas (e.g., not connected to a federally enforceable permit limiting annual net electric sal es to the product of their design net efficiency times their potential electric output or lessnatural gas pipeline); (4) utility boilers and IGCC units that have always been subjec t to a federally enforceable permit limiting annual net- electric sales to one-third or less of their potential electric ou tput (e.g., limiting hours of operation to less than 2,920 hour s annually) or limiting annual electric sales to 219,000 MWh or less; (5)

116 We refer to the capability to supply 25 MW net to the grid as the "total electric sales criterion."*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 120 of 854 municipal waste combustors that are subject to subp art Eb of this part; and (6) commercial or industrial solid w aste incineration units subject to subpart CCCC of this part. D. Units Not Covered by Thisthis Final Rule

As described in the previous section, the EPA is no t issuing standards of performance for certain types of sources – specifically , dedicated non-fossil fuel -fired (e.g., biomass) units and industrial combined heat and power ( CHP ) units ., as well as certain projects under development. This section discusses these sources and our rationale for not i ssuing

standards for them. SinceBecause the rationale applies to both steam generating units and combustion turbines , we are describing it here instead ofrather than in the separate steam generating unit and combustion turbine discussions. We discuss the proposed applicability criteria, the topics whe re the agency solicited comment, a brief summary of the relevant comments, and the rationale for the final applicability approach to for these

sources. 1. Dedicated Non-fossil and BiomassFuel Units The proposed applicability for newly constructed EG Us included EGUsthose that primarily combust fossil fuels (e.g., coal, oil , and natural gas). The specificproposed applicability criteria waswere that affected units must burn fossil fuels for more than 10 percent of the unit’s total heat input , on average ,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 121 of 854 over a 3-year average.period. 117 Under the proposed approach, applicability withunder the final NSPS for GHGCO 2 emissions could changehave changed on an annual basis depending on the composition of fuel burned. We solicited multiple

commentscomment on several aspects of the proposed applicability criteria for non-fossil fuel units. Specifically, we solicited comment on a broad applicability approach that woul d include non-fossil fuel -fired units as affected units , but that would impose an alternate standard when the unit fires fossil fuels

for 10 percent or less fossil fuels of the heat input during the applicable 3-year applicability- determination period. We solicited comment on whether, if such a subcategory is warranted, the applicability-determination period f or the subcategory should be 1-year or a 3-year rolling pe riod. We also solicited comment on whether the standard for such a subcategory should be an alternate numerical limit or "no emiss ion

standard." While the proposed exemption applied to all non-fos sil fuels, most commenters focused on biomass-specific issues. Many commenters supported an exclusion for biomass- fired units based on firing that fire no more than 10 percent fossil fuels. Some comment ers suggested that the exclusion for biomass-fired units should be raised to a 25 pe rcent fossil fuels fuel-use threshold. Conversely, some commenters supported standards for biomass

117 We refer to the fraction of heat input derived fro m fossil fuels as the "fossil fuel-use criterion." Formatted: Font: +Body (Calibri), 11 pt, Font color: Auto

Formatted: Font: +Body (Calibri), 11 pt, Font color: Auto Formatted: Font: +Body (Calibri), 11 pt, Font color: Auto Formatted: Font: +Body (Calibri), 11 pt, Font color: Auto*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 122 of 854 units because they are typically operated with high er heat rates than coal units and model results conducted by the EPA using IPM show that biomass generation is expected to quadrup le over the next 10 years. These commenters said biomass units should be regulated consistently with coal units. One comment er supported the EPA's interest in ensuring that the CO 2 standards issued pursuant to CAA section 111(d) continue to apply to existing EGUs when those EGUs modify or reconstruct in ways that cause the units to derive 10 percent or less of their hea t input from fossil fuel because the commenter stated that allow ing modified and reconstructed EGUs to escape 111(d) standards w ould undermine the coherence of the proposed 111(d) regu latory system. Some commenters supported a 3-year period f or determining applicability; other commenters support ed a 12-month rolling period while others supported a one-time de termination.

Some commenters stated that the standard was not de veloped to include biomass-fired units, and none of the ana lyses supporting the standard includes biomass-fired unit s. Commenters also stated that the proposed standard has not been adequately demonstrated as achievable by these units, and the rule offered no basis for regulating sources that combust insign ificant amounts of fossil fuels. These commenters suggested that if biomass units must be included under these CAA sect ion 111 standards for fossil fuel units, they should be inc luded in a*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 123 of 854 separate subcategory after a subsequent proposal an d comment period based on relevant data from biomass-fired un its. Many commenters wanted CO 2 emissions from biomass (when cofired with fossil-fuels) to be excluded from applic ability and compliance determinations. These commenters stated that the final national standard for CO 2 emissions should encourage the use of biomass-fired units because this will encour age investments in forests which are natural sinks for atmospheric carbon. These commenters said that the EPA should p rovide a holistic document analyzing all issues relevant to sound policy for treatment of biomass units under GHG regulation s after the Revised Framework for Assessing Biogenic CO 2 Emissions from Stationary Sources is released and provide stakehol ders additional time to comment. Some commenters said th at biogenic

CO 2 from EGUs should be accounted for by adopting the current framework for biogenic emissions under 40 CFR part 98. Other commenters suggested that biomass-fired units shoul d receive credits toward compliance since their biogenic CO 2 can be considered sequestered within the forest product in ventories and markets where they procure their fuelssupported the proposed 3- year averaging period for the fossil fuel-use crite rion because it provides greater flexibility for operators to us e fossil fuels when supply chains for the primary non-fossil fuels are disrupted, during unexpected malfunctions of the pr imary non-*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 124 of 854 fossil fuel handling systems, or when the unit’s ma ximum generating capacity is required by system operators for reliability reasons. Many commenters supported the 3-year averaging period because it is consistent with the final requirements under the EPA’s Mercury and Air Toxics Standards (MATS) and would allow non-fossil fuel-fired units to use some fossil fuels for flame stabilization without trigge ring applicability. Some commenters requested that the E PA clarify the method an operator should use during the first 3 years of operations to determine if a particular unit will m eet the 10 percent fossil fuel-use threshold. Others asked whe ther or not an affected facility has a compliance obligation du ring the first 3-year period and, if an affected facility do es not meet the 10 percent fossil fuel-use threshold during sev eral 12-month periods during the first 3 years, whether complianc e calculations would be required for such 12-month pe riods. Other commenters had concerns with the 3-year averaging p eriod, stating that a source would no longer be subject to the NSPS if it fell below the threshold for any of the applicab ility metrics that the EPA proposed to calculate on a 3-year (or, in some cases, annual) basis. They argued that this would c reate a situation in which no one would know whether a part icular plant will be subject to the standards until years after the emissions had already occurred. Some commenters were concerne d that plants*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 125 of 854 operating near the threshold could move in and out of the regulatory system, which would provide complication s for compliance, enforcement, and permitting

. TheAfter considering these comments, the EPA has concluded that the proposed applicabilityfossil fuel-use criterion based on the actual amount of fossil fuel burned is not a practicalan ideal approach to define units subject to the rule. Facilities anddetermine applicability. As commenters pointed o ut, facilities, permitting authorities , and the public would not

know , when construction is commenced , whether a facility will be subject to the final NSPS is applicable , and after operation has

commenced , a unit could move in and out of applicability each year. The intent of this rulemaking is to establish GHGCO 2 standards for fossil fuel-fired EGUs, not for non-f ossil fuelfired EGUs. Therefore, to clarifysimplify compliance and establish GHGCO 2 standards for fossil fuel-fired EGUs,only those sources which we have determined this rule will not set GHG emission standards for units out to regulate, we ar e finalizing a fossil fuel-use criterion that will exempt dedica ted nonfossil units. Specifically, units that are capable of burning 50 percent or more non-fossil fuel are exempt from the final standards so long as they are subject to a federally enforceable permit that limits thetheir use of fossil fuels to less than 10 percent or less of thetheir heat input capacity on an annual*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 126 of 854 basis. This approach allows existing fossil fuelfiredestablishes clear applicability criteria and a voids the prospect of units moving in and out of applicabilit y based on their actual fuel use in a given year. Consistent w ith the applicability approach in the steam generating units to modify their operating permits to limit the use of fossil fuels such that the unit would no longer be considered fossil fuel-fired

EGUs. The unit would criteria pollutant NSPS, subpart Da, the final fossil fuel-use criterion does not include “c onstructed for the purpose of” language. Therefore, an owner o r operator could change a unit’s applicability in the future b y seeking a modification of the unit’s permit conditions. A uni t with the appropriate permit limitation will not be subject to the 111(b)

GHG requirements in this rulemaking and states. Similarly, an existing unit that takes a permit limitation restri cting fossilfuel use would no longer be required to include them in theiran affected unit for the purposes of 111(d) planstate plans . This is consistent with theour intent to reduce GHG emissions from fossil fuel-fired EGUs. We considered the fossil use restriction on bothusing either an annual andor 3-year average . We have for calculating compliance with the final fossil fuel-use criterion . Ultimately,

we concluded that the single year an annual average fossil-fuel use based on the annual capacity factor, and not th e actual*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 127 of 854 percent of fossil burned, provides would provide sufficient flexibility for dedicated non-fossil fuel-fired units to combust fossil fuels for flame stabilization and other anci llary

purposes . A 3-year exemption based on capacity factor would not cover limited use fossil fuel EGUs, while maintaini ng consistency with the 12-month compliance periods us ed for most permit limitations. A 3-year average potentially wo uld allow units to combust a significant quantity of fuels in a given year, leading to higher CO 2 emissions, so long as they curtailed fossil-fuel use in a later year. This would defeat the purpose of the criterion, which is to exempt dedicated non- fossil units only. Finally, we are finalizing the 10 percent fos sil-fuel use threshold in relation to a unit’s heat input capaci ty rather than its actual heat input , which is not the intent of the provision.consistent with past approaches we have t aken under the industrial boiler criteria pollutant NSPS. 2. Industrial Combined Heat and PowerCHP Units Another approach to generating electricity is the u se of combined heat and power ( CHP ) units. A CHP unit can use a boiler, combustion turbine, reciprocating engine, andor various

other generating technologies to generate electricity an d useful thermal energy in a single, integrated system. CHP units are generally more efficient than conventional power pl ants because the heat that is normally wasted in a conventional power*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 128 of 854 generation iscooling system (e.g., cooling towers) is instead recovered as useful thermal output. While the EPA d id propose

some applicability provisions specific to CHP units (e. g., subtract purchased power of adjacent facilities whe n determining

nettotal electric sales), in general , the proposed applicability criteria for electric-only units and CHP units waswere similar. The intent of the proposed nettotal and percentage electric

sales applicability approachcriteria was to cover only utility , and CHP units, not industrial , CHP units . To the extent that the proposal’s applicability provisions hadwould have the effect of includingcovering industrial CHP units , we solicited comment on

an appropriate applicability exemption, and the criteria for that exemption, for highly efficient CHP facilities . We also solicited comment on eliminating the 219,000 MWh an nual electric sales criterion for stationary combustion turbines based CHP

. Many commenters supported the exclusion of CHP units as a means of encouraging capital investments in highly efficient and reliable distributed generation technologies. CommentersThese

commenters recommended incorporation ofthat the EPA adopt an explicit exemption for CHP units at facilities that are classified as industrial (e.g., gas-fired CHPs with in SIC codes 2911 – petroleum refining, 13 – oil and gas extract ion, and other industrial SIC codes as appropriate). CommentersThey also stated that the EPA should exclude CHP units that h ave an energy*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 129 of 854 savings of 10 percent or more compared to separate heat and

power. AOne commenter statedsuggested that the final rule should restrict the definition of affected facility to inc ludecover only industrial-commercial-institutional CHP units that supply, on a net basis, more than two-thirds of their poten tial combined thermal and electric energy output and more than 45 0,000 MWh net-electric output to a utility power distribution system on an annual basis for 5five consecutive calendar years and. The commenter also suggested that CHP units which have total thermal energy production that approaches or exceeds the unit'stheir total electricity production should be exempted. Commenters offered a number of strategies for incor porating an exemption for CHP units including Other commente rs suggested exempting CHP units by fuel type and exempting industrial CHP units or based on the definition of potential electric outpu t. It wasFor example, some commenters suggested thatmodifying the percentpercentage electric sales threshold to be based on the net system efficiency ( that includes including useful thermal output) rather than just the rated net-electric-output efficiency , or. They also suggested that the applicability criteria should use a default efficiency of 50 percent for CHP units. Some commenters suggested an exclusion wherethat a CHP units wouldunit should not be considered to bean affected

EGUsEGU if 20 percent or more of theirits total gross or net*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 130 of 854 energy output consistsconsisted of useful thermal output on a 3- year rolling average basis. SomeOther commenters said an exemption for that highly efficient CHPsCHP units that achieve an overall efficiency level of 60 orto 70 percent andor higher

should be excluded . Some commenters opposed removal of the sales criterion (219,000 MWh) because it ensures that ind ustrial CHP are not subject to the standards, and the commenter believes that these highly efficient operations should not b e encumbered by the regulatory burdens of the proposed standard. from applicability. In general, the inherent efficiency of CHP minimize s GHG emissions relative to separate generation of heat a nd power and since CHP would comply with the final GHG standards there is limited environmental benefit to including CHP with significant environmental benefits in this GHG NSPS. In additio n, the The intent of this rulemaking is to cover only utility CHP since it serves units, because they serve essentially the same purpose as

an electric-only EGU, but not industrialEGUs (i.e., the sale of electricity to the grid). Industrial CHP units since they, on the other hand, serve a different primary purpose . The (i.e., providing useful thermal output with electric sales as a byproduct). With these facts in mind and after consid ering the comments, the EPA has concluded that it is important to consider appropriate to consider two factors for the final C HP exemption:*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 131 of 854 (1) whether the primary purpose of the CHP unit is to provide useful thermal output rather than electricity and ( 2) whether the CHP unit is highly efficient and thus achieves environmental benefits. We rejected many of the approaches suggested by the commenters because they did not achieve one or both purpose and efficiency when determining the scope of this rulem aking. Theof the factors we identified. Specifically, the EPA , therefore, concludes that it is appropriate to not include in the scope of this rulemaking CHP whose primary purpose is provid ing useful thermal output and CHP with significant environment al benefit. To distinguish by purpose, the EPA concludes that has concluded

that SIC code classification is not a sufficient measure of purpose for the purposes of this rulemaking since i t is only randomly related to the electric sales of a particu lar CHP unit.indicator of the purpose (i.e., it does not co rrelate to useful thermal output) or environmental benefits (i .e., efficiency) of a unit. Further, an exemption based on SIC code could result in circumvention of the intended appli cability. For example, this approach would allow a new EGU to loc ate near an industrial site, provide a trivial amount of useful thermal output to that site, sell electricity to the grid, and nonetheless avoid applicability. Similarly, increas ing the electric sales criteria to two-thirds of potential electric*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 132 of 854 output and 450,000 MWh would essentially amount to a blanket exemption that tells us nothing about the primary p urpose or efficiency of the unit. The EPA concludes that percent of electric sales re lative to the potential electric output is an appropriate measure of purpose since electric sales are inherent in the so urce category definition. The EPA considered multiple efficiency options to identify CHP with significant environmental benefit . We have concluded that overall design efficiency is not an appropriate method to determine environmental benefit.On the ot her hand, exemptions based on useful thermal output being gre ater than 20 percent of total output, thermal output being great er than electric output, or overall design efficiency value would identify whether the primary purpose of a unit is t o generate thermal output, but they would not recognize the en vironmental benefits of highly efficient CHP units. While overa ll efficiency may appear to be a good indicator of environmental benefits, this is not always the case with CHP units. Overall efficiency is a function of both efficient design and the powe r to heat ratio (the amount of electricity relative to the am ount of useful thermal output). For example, boiler-based CHP units withtend to produce large amounts of useful thermal output relative to electric output and tend to have higherhigh overall efficiencies than CHP with lower. For units producing primarily*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 133 of 854 useful thermal output, the equivalent separate heat and power efficiency (i.e., the theoretical overall efficienc y if the electricity and useful thermal output were produced by a standalone EGU and stand-alone boiler) would approach th at of a stand-alone boiler (e.g., 80 percent). However, com bustion turbine-based CHP units tend to produce relatively equal amounts of relativeelectricity and useful thermal output. In this case, the equivalent separate heat and power efficiency w ould be closer to 65 percent. Therefore, an exemption based on overall efficiency without considering the relative amount of electricity to useful thermal output does not ident ify the relative GHG reductions of a is not an indication o f the fuel savings a CHP unit will achieve relative to separat e heat and power. Further, this approach would encourage the d evelopment of CHP units that just meet the efficiency exemption c riterion and would still cover many combustion turbine-based ind ustrial CHP units. Conversely, while an exemption based on fuel savings relative to separate heat and power would recognize the environmental benefit of highly efficient CHP units , it would not consider the primary purpose of the CHP unit. Based on public comments and after further analysis In the end , the EPA makes has concluded that maintaining the proposed percent age electric sales criterion with two adjustments to addresses both factors with which we are concerned. First, we are changing the definition of applicability of this rule to CHP. The first is to base*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 134 of 854 the definition of “ potential electric output ” to be based on overall net efficiency at the maximum electric production rate , instead of just electric-only efficiency. Second, the GHG standard applicability would be based on we are changing the percentage electric sales criterion to reflect the sliding sca le, which is the overall design efficiency , calculated at the maximum useful thermal rating of the CHP unit (e.g. , a CHP unit with a extraction condensing steam turbine would determine the efficiency at the maxim um extraction/bypass rate), of the unit multiplied by the unit’s potential electric output instead of one-third of the potential electric output as proposed. We are defining utility CHP as a CHP unit that is: (1) technically capable of selling more electricity tha n the product of its design efficiency multiplied by its This app roach recognizes the primary purpose of industrial CHP un its by providing a more generous percentage electric sales exemption to CHP units with high thermal output. As described pr eviously, CHP units with high thermal loads tend to be more effic ient and will therefore have a higher allowable percentage electr ic sales. By amending both the definition of “ potential electric output and (2) not ” and the electric sales threshold, we assu re that CHP units that primarily produce useful thermal output are exempted as industrial CHP units even if they are selling al l of their electric output to the grid. As the relative amount of electricity generated by the CHP unit increases, ef ficiency will generally decrease, thus limiting allowable electri c sales before applicability is triggered. This approach al so recognizes*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 135 of 854 the environmental benefits of increased efficiency by encouraging industrial CHP units to be designed as efficiently as possible to take advantage of the higher electri c sales permitted by the sliding scale. In conclusion, a CHP unit will be an affected sourc e unless it is subject to a federally enforceable permit limitingthat limits annual nettotal electric sales to less than this amount (or equal to the unit’s design efficiency multiplied by its potential electric output ) or 219,000 MWh, 118 whichever is greater. The net impact of these changes is toThis final applicability criterion will only cover CHP units that condense

a largesignificant portion of steam generated by the unit forand

use the purposeelectric power generated as a result of supplyingcondensing that steam to supply electric power to the grid. CHP facilities that do not have a condensing steam turbine (e.g., simple cycle combustion turbines withturbine-based CHP units without a HRSGsteam turbine and boiler - based systems with a backpressure steam turbine) would generally not b e physically capable of selling enough electricity to meet the a pplicability criteria –criterion, even if they sold 100 percent of the electricity generated and did not subtract out the

118 The EPA has concluded that it is appropriate to mai ntain the 219,000 MWh total electric sales criterion for comb ustion turbine based CHP units to avoid potentially coveri ng smaller industrial CHP units.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 136 of 854 electricelectricity used by the thermal host(s). The EPA has concluded that this is appropriate sincebecause these designssources are industrial by design and provide mostly useful thermal output. CHP facilities with a steam extraction condensing s team turbine wouldwill determine their potential electric output based on their design efficiency on a net basis at the maximum electric production rate at the base load heat input rating . The owner/operator would be able to determine during (e .g., the CHP is condensing as much steam as possible to create e lectricity instead of using it for useful thermal output). We have concluded that it is necessary for CHP units with e xtraction condensing steam turbines to calculate their potent ial electric output at the maximum condensing level to avoid cir cumvention of the applicability criteria. For example, to avoid a pplicability a CHP unit could locate next to an industrial host and have the capability of selling significant quantities of use ful thermal output without ever actually intending to supply mu ch, if any, useful thermal output to the industrial host. If we calculated the potential electric output at the maximum level of thermal output, this type of CHP unit could operate at full condensing mode at base load conditions for the entire year an d still not exceed the electric sales threshold. During the permitting

process if the EGU GHG NSPS was applicable. , the owner or*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 137 of 854 operator will be able to determine if the unit is s ubject to the final standards in this rule. New EGUs with only limited useful thermal output wouldwill be subject to the final standards, but the vast maj ority of new

CHP would units will be classified as industrial CHP an d will not be subject to the final standards. The EPA has concluded

that this approach is similar to exempting CHP facilitie s that sell less than half of their total output (electric ity plus thermal), but has the benefit of accounting for the overall design efficiency. This approach both limits applic ability to

the intendedindustrial CHP units and encourages the installation of the most efficient CHP systems sincebecause more efficient designs wouldwill be able to have higher permitted electric sales while not being subject to the GHGCO 2 standards included in this rulemaking. 3. Municipal Waste Combustors and Commercial and In dustrial Solid Waste Incinerators The purpose of this rulemaking is to establish CO 2 standards for fossil fuel-fired EGUs. Municipal waste combust ors and commercial and industrial solid waste incinerators typically

have not been typically included in this source category. Therefore, even if one of these types of units meet s the general heat input and electric sales criteria , we are not finalizing CO 2 emission standards for municipal waste combustors s ubject to*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 138 of 854 subpart Eb of this part and commercial and industri al solid waste incinerators subject to subpart CCCC of this part. 4. Certain Projects under Development The EPA proposed that a limited class of projects u nder development should not be subject to the proposed s tandards. These were planned sources that may be capable of c ommencing construction (within the meaning of section 111 (a) ) shortly after the standard’s proposal date, and so would be classified as new sources, but which have a design which would be incapable of meeting the proposed standard of performance. Se e 79 FR 1461 and CAA section 111 (a)(2). The EPA proposed that t hese sources would not be subject to the generally-applicable st andard of performance, but rather would be subject to a unit- specific permitting determination if and when construction a ctually commences. The EPA indicated that there could be th ree sources to which this approach could apply, and further ind icated that the EPA could ultimately adopt the generally-applic able standard of performance for these sources (if actually const ructed). 79 FR 1461. As explained at Section III.J below, the EPA is fin alizing this approach in this final rule. We again note tha t these sources, if and when constructed, could be ultimate ly subject to the 1,400 lb CO 2 /MWh-g standard, especially if there is no*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 139 of 854 engineering basis, or demonstrated action in relian ce, showing

that the new source could not meet that standard.

E. Coal Refuse

In the originalApril 2012 proposal, we requestedsolicited comment on subcategorizing and exempting EGUs that burn over 75 percent coal refuse on an annual basis. Multiple co mmenters supported the exemption, citing numerous environmen tal benefits of remediating coal refuse piles. Observing that co al refusefired EGUs typically use fluidized bed technologies , other commenters disagreed with any exemption, specifical ly citing the

N 2 O emissions from fluidized bed boilers. In light of the environmental benefits of remediating coal refuse p iles cited by commenters, the limited amount of coal refuse, and the fact that a new coal refuse-fired EGU would be located in clo se proximity to the coal refuse pile, in the January 2014 proposal, we sought additional comments regarding a subcategory for coa l refusefired EGUs in the January 2014 proposal . Specifically, we requested additional information on the net environ mental benefits of coal refuse-fired EGUs and information to support an appropriate emissions standard for coal refuse-fire d EGUs. One commenter on the April 2012 proposal stated that ex isting coal refuse piles are naturally combusting at a rate of 0.3 percent annually, and we requested comment on this rate and the proper*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 140 of 854 approach to account for naturally occurring emissio ns from coal refuse piles in the January 2014 proposal. Commenters said that a performance standard is not feasible for coal refuse CFBs since there is no economically feasible way to capture CO 2 through a conveyance designed and constructed to capture CO 2 . Commenters said that National Emission Standards fo r Hazardous Air Pollutants (NESHAPs) and work practic e standards which have recently been passed do enough to limit emissions from coal refuse plants andCommenters suggested that the EPA establish BSER for GHGs at modified coal refuse CFB s as a boiler tune-up that must be performed at least every 24 mo nths. Commenters stated that the EPA should exempt coal r efuse CFB units relative to their CO 2 emissions to the extent that these units offset the uncontrolled ground level emission s from spontaneous combustion of legacy coal refuse stockp iles and noted that the mining of coal waste not only produc es less emissions in the long term, but also helps to recla im land that is currently used to store coal waste. In contrast, one commenter saw no legitimate basis for coal refuse t o be subcategorized and theystated that it should be treated in the same manner as all other coal-fired EGUs. The EPA has concluded that an explicit exemption or subcategory specifically for coal refuse-fired EGUs is unnecessary.not appropriate. The costs faced by coal refuse*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 141 of 854 facilities to install CCS are similar to coal-fired EGUs burning any of the primary coals, and the final applicable requirements and standards in the rule do not preclude the devel opment of new coal refuse-fired EGUs.units without CCS. Specifically, we are not finalizing CO 2 standards for industrial CHP units. Many existing coal refuse-fired EGUsunits are relatively small and designed as CHP units. ADue to the expense of transporting coal refuse long distances, we anticipate that any new coal refusefired EGU would be relatively small in size. Moreover, sites with sufficient thermal demand exist such that the unit could be designed as an industrial CHP facility and the requ irements of this rule would not apply. F. Format of the Output- Basedbased Standard For a non-CHP EGU, gross output is the electricity generation measured at the generator terminals. 1. Net and Gro ss Outputbased Standards Net output is the gross electrical output less the unit’s total parasitic (i.e., auxiliary) power requirements. A parasitic load for an electric generating unit is a load or device powered by electricity, steam, hot w ater, or directly by the gross output of the electric genera ting unit that does not contribute electrical, mechanical, or useful thermal output. In general, parasitic energy demand s include less than 7.5 percent of non-IGCC and non-CCS coal- fired station power output, approximately 15 percent of non-CCS I GCC-based*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 142 of 854 coal-fired station power output, and about 2.5 perc ent of nonCCS combined cycle station power output. The use of CCS increases both the electric and steam parasitic loads used internal to the unit, and these outputs are not considered whe n determining the emission rate. Net output is used to recognize the environmental benefits of (1) EGU designs and contr ol equipment that use less auxiliary power, (2) fuels that requi re less emissions control equipment and (3) higher efficien cy motors, pumps, and fans. For all newly constructed units, the EPA proposed s tandards as gross output emission rates consistent with curr ent monitoring and reporting requirements under 40 CFR part 75. 119 For a non-CHP EGU, gross output is the electricity generation measured at the generator terminals. However, we solicited comment on finalizing equivalent net-output-based s tandards either as a compliance alternative or in lieu of th e proposed gross-output-based standards. Net output is the gross electrical output less the unit’s total parasitic (i.e., auxil iary) power requirements. A parasitic load for an EGU is a load or device powered by electricity, steam, hot water, or direct ly by the gross output of the EGU that does not contribute el ectrical, mechanical, or useful thermal output. In general, p arasitic energy demands include less than 7.5 percent of non -IGCC and

119 79 FR 1447-48.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 143 of 854 non-CCS coal-fired station power output, approximat ely 15 percent of non-CCS IGCC-based coal-fired station po wer output, and about 2.5 percent of non-CCS NGCC power output. The use of CCS increases both the electric and steam parasitic loads used internal to the unit, and these outputs are not con sidered when determining the emission rate. Net output is used to recognize the environmental benefits of: (1) EGU designs and control equipment that use less auxiliary power; (2) fuels that require less emissions control equipment; and (3) higher ef ficiency motors, pumps, and fans. For modified and reconstructed combustion turbines, the EPA also proposed standard s as gross output emission rates, but solicited comment on fin alizing net output standards. The rationale was that due to the low auxiliary loads in non-CCS combined cycleNGCC designs, the difference between a gross-output standard and a ne t-output standard has a limited impact on environmental perf ormance. Auxiliary loads are more significant for modified a nd reconstructed boilers and IGCC units, and the EPA p roposed standards on a net output basis for these units. Th e rationale included that this would enable owners/operators of these types of units to pursue projects that reduce auxiliary l oads for compliance purposes. However, the EPA solicited com ment on finalizing the standards on a gross-output basis. W e also proposed to use either gross-output or net-output b ases for each*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 144 of 854 respective subcategory of EGUs (i.e., utility boile rs, IGCC units, and combustion turbines) consistently across all CAA section 111(b) standards for new, modified, and rec onstructed

EGUs. Many commenters supportsupported gross-output-based

standards because they believe, maintaining that a net - output standard penalizes the operation of air pollution c ontrol equipment. Several commenters disagreed with the Agency'sagency's proposed rationale that a net - output standard would provide incentive to minimize auxiliary loads . The commenters believe utility commissions and existing economic forces already provide utilities with appropriate incentives to properly manage all of these factors. Some commente rs supported a gross-output basis-based standard because variations in site conditions (e.g., available natural gas pressure, a vailable cooling water sources, and elevation) will likely p enalize some owners and benefit others simply through variations in their particular plant - site conditions if a net basis is used. Several commenters stated that if the final rule in cludes a netoutput-based standard, it should be included as an option in conjunction with a gross-output-based option. Several commenters opposed net-output-based standar ds because they believe it is difficult to accurately determine the net output of an EGU. They pointed out that many fa cilities have*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 145 of 854 transformers that support multiple units at the fac ility, making unit-level reporting difficult. These commenters al so stated that station electric services may come from outsid e sources to supply certain ancillary loads. One commenter state d that the benefit of switching to net-output-based standards would be small and would not justify the substantial complex ities in both defining and implementing such a standard. Converse ly, other commenters stated that net-metering is a well-estab lished technology that should be required, particularly fo r newly constructed units. Other commenters, however, believemaintained that the final rule should strictly require compliance on a net ou tput-basis. They believe that this is the only way for the standards to minimize the carbon footprint of the electricity de livered to

consumers and are the only standards that are truly “technol ogy forcing.”. These commenters believe that, at a minimum, netoutput-based standards should be included as an opt ion in the final rule. The EPA recognizes that evaluating compliance on a netoutput basis more closely evaluates the environment al performance of the sector. However, the Agency also recognizes that the majority of EGU owners/operators currently use the data acquisition and handling technologies that have bee n developed and validated for Part 75 compliance. Currently, Pa rt 75 only*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 146 of 854 allows the reporting of gross energy output. In add ition, many of the IGCC facilities are co-production facilities (i.e., they produce useful byproducts and chemicals along with electricity). As noted in the proposal, we have concluded that me asuring the net electricity at these co-production facilities w ould be more challenging to implement. Based on further evaluation and review of issues ra ised by commenters, for combustion turbines the EPA is fina lizing the CO 2 standard for EGUs in a format that is similar to th e current NSPS format for criteria pollutants. The default final standards establish a grossoutput-based standard. This allows owners/operators of new combustion turbines to comply with the

CO 2 emissions standard under Part 60 using the same da ta currently collected under Part 75. However, many permitting authorities have concluded that the environmental benefits of using net-output-based st andards outweigh any additional complexities for particular units and have required them in recent GHG operating permits. We expect this trend to continue. Therefore, owners/operators of combustion turbines may petition the permitting aut hority to use the alternate net-output-based standard. If the per mitting authority grants the petition, owners/operators wou ld comply with a net-output-based standard that we have concl uded is essentially equivalent to the gross-output-based st andard. This approach establishes a single applicable NSPS CO 2 emission standard (i.e., units would not switch between the gross and*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 147 of 854 net-output-based standards unless the Administrator grants a petition to switch) and supports the continued use of netoutput-based standards in future GHG permits. Addit ionally, having an NSPS standard that is measured using the same monitoring equipment as required under the operatin g permit minimizes compliance burden. If a combustion turbin e were subject to both a gross and net emission limit, mor e expensive higher accuracy monitoring could be required for bo th measurements. Finally, this approach accommodates p otential future reporting of net output under part 75. In contrast, weWe are only finalizing gross-output-based standards for utility boilers and IGCC units. Provi ding an alternate net-output-based standard that is based o n grossoutput-based emissions data and an assumed auxiliar y load is most appropriate when the auxiliary load can be rea sonably estimated and the choice between the net

- and gross-output-based standard will not impact the identified BSER. For e xample, the auxiliary load for combustion turbines the auxiliary load is relatively fixed and small, approximately 2.5 perce nt, so the choice between thea gross and net-output-based standard will not substantially impact technology choices. However, i n the case of utility boilers, we have concluded that we do not have sufficient information to establish an appropriate net-outputbased standard that would not impact the identified BSER for*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 148 of 854 these types of units. The BSER for newly constructe d utility boilerssteam generating units is based on the use of partial CCS. However, unlike the case for combustion turbin es, owners/operators of utility boilers have multiple t echnology pathways available to comply with the actual emissi on standard. The choice of both control technologies and fuel im pact the overall auxiliary load. For example, a coal-fired h ybrid EGU (e.g., one that includes integrated solar thermal equipment for feedwater heating or steam augmentation) or a coal- fired EGU cofiring natural gas would have lower non-CCS related auxiliary

loads and since, because the required amount of CCS needed to comply with the standard would also be smaller , the CCS auxiliary loads would also be reduced. Therefore, w e cannot identify an appropriate assumed auxiliary load to e stablish an equivalent output-based standardnet-output-based standard. In addition, many IGCC facilities (which could be used as an alternative technology for complying with the stand ard of performance; see Sections IV.B and V.P below) have been proposed or are envisioned as co-production facilities (i.e. , to produce useful by-products and chemicals along with electri city). As noted in the proposal, we have concluded that predi cting the net electricity at these co-production facilities would be more challenging to implement under these circumstances

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 149 of 854 For combined heat and power units, useful thermal o utput is also used when determining the emission rate.In con trast, based on further evaluation and review of issues raised b y commenters, the EPA is finalizing the CO 2 standard for combustion turbine EGUs in a format that is similar to the current NSP S format for criteria pollutants. The default final standards establish a gross-output-based standard. This allows owners/ope rators of new combustion turbines to comply with the CO 2 emissions standard under Part 60 using the same data currently collect ed under Part

75. 120 However, many permitting authorities commented persuasively that the environmental benefits of usi ng netoutput-based standards can outweigh any additional complexities for particular units, and have indeed adopted net-o utput standards in recent GHG operating permits for combu stion turbines. We expect this trend to continue and have concluded that it is appropriate to support the expanded use of netoutput-based standards, and therefore are allowing certain sources to elect between gross output-based and net -output-based

120 Additionally, having an NSPS standard that is meas ured using the same monitoring equipment as required under the operating permit minimizes compliance burden. If a combustion turbine were subject to both a gross and net emission limit, mor e expensive higher accuracy monitoring could be required for bo th measurements.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 150 of 854 standards. Only combustion turbines are eligible to make this election. The rule specifies an alternative net-output-based standard of 1,030 lb CO 2 /MWh-n for combustion turbines. This standard is equivalent to the otherwise-applicable gross-output -based standard of 1,000 lb CO 2 /MWh-g. 121 The procedures for requesting this alternative net- outputbased standard require the owner or operator to pet ition the Administrator in writing to comply with the alterna te applicable net-output-based standard. If the Administrator gra nts the petition, this election would be binding and would be the unit’s sole means of demonstrating compliance. Owners or o perators complying with the net-output-based standard must s imilarly petition the Administrator to switch back to comply ing with the gross-output-based standard. 2. Useful Thermal Output For CHP units, useful thermal output is also used w hen determining the emission rate. Previous rulemakings issued by

the EPA usehave prescribed various ‘“ discount factors’ when determining how muchfactors” of the measured useful thermal output isto be used when determining the emission rate. We proposed that 75 percent credit is the appropriate discount

121 Assuming a 3 percent auxiliary load for the NGCC s ystem.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 151 of 854 factor for useful thermal output, and we solicited comment on a range from two-thirds to three-fourths credit for u seful thermal output in the proposal for newly constructed units and twothirds to one hundred percent credit in the proposa l for modified and reconstructed units. The 75 percent cr edit was based on matching the emission rate , but not the overall emissions, of a hypothetical CHP unit to the proposed emissio n

rate. Many commenters said that in order to fully account for the environmental benefits of CHP and to reflect the en vironmental benefits of CHP, the EPA should allow 100 percent o f the useful thermal output from CHP units. Commenters noted tha t providing 100 percent credit for useful thermal output is con sistent with the past practice of the EPA in the stationary comb ustion turbine criteria pollutant NSPS and Statestate approaches for determining emission rates for CHP units. Based on further consideration and review of the co mments submitted, we are finalizing one hundred100 percent credit for useful thermal output for all newly constructed, mo dified, and

reconstructed CHP sources. This approach approximately matches the overall GHG emissions from a hypothetical CHP f acility to separate heat and power andWe have concluded that t his is appropriate because, at the same reported emission rate, a hypothetical CHP unit would have the same overall G HG emissions*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 152 of 854 as the combined emission rate of separate heat and power facilities. Any discounting of useful thermal outpu t could distort the market and discourage the development o f new CHP units. Full credit for useful thermal output appropriately recognizes the environmental benefit of CHP.

G. CO 2 Emissions Only ThisThe air pollutant regulated in this final action regulatesis greenhouse gases. However, the standard s in this rule are expressed in the form of limits on only emissions of

CO 2 , and not the other constituent gases of the air po llutant

GHGs. We identify the pollutant we are regulating as GHG s, but are only setting standards for CO 2 emissions. 122 We are not establishing a limit on aggregate GHGs or separate emission limits for other GHGs (such as methane (CH 4 ) or nitrous oxide (N 2 O)) as theyother GHGs represent less than 1 percent of total estimated GHG emissions (as CO 2 e) from fossil fuel-fired electric power generating units. 123 Notwithstanding this form of the

122 As noted above, in the Endangerment Finding, the E PA defined the relevant “air pollution” as the atmospheric mix of six longlived and directly-emitted greenhouse gases: carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexaflu oride (SF 6 ). 74 FR 66497. 123 EPA Greenhouse Gas Reporting Program; www.epa.gov/ghgreporting/.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 153 of 854 standard, consistent with other EPA regulations add ressing GHGs, the air pollutant regulated in this rule is GHGs. 124 H. Legal Requirements for Establishing Emission Sta ndards 1. Introduction In the January 2014 proposal, we described the prin cipal legal requirement for standards of performance unde r CAA section 111(b), which is that the standards of performance must consist of standards for emissions that reflect the degree of emission limitation achievable though the application of the “best system of emission reduction ... adequately demonstrated,” taking into account cost and any nonairnon-air quality health and environment impact and energy requirements (BSER).. We noted that the D.C. Circuit has handed down numerous deci sions that interpret this CAA provision, including its compone nt elements, and we reviewed that case law in detail. 125 We received comments on our proposed interpretation , and in light of those comments, in this rule, we are clari fying our interpretation in certain respects. We discuss our interpretation below. 126

124 See 77 FR 31257-30 (June 3, 2010). 125 79 FR 1430, 1462 (January 8, 2014). 126 We also discuss our interpretation of the requirem ents for standards of performance and the BSER under section 111(d), for existing sources, in the section 111(d) rulemaking that the EPA is finalizing simultaneously with this rule. Our interpretations and applications of these requirements in the two*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 154 of 854 2. CAA requirementsRequirements and Court Interpretation As noted above, the CAA section 111 requirements th at govern this rule are as follows: As the first step towards establishing standards of performance, the EPA “sha ll publish

....

. . a list of categories of stationary sources

.... . . [that] cause[], or contribute[] significantly to, air poll ution which may reasonably be anticipated to endanger public he alth or

welfare.” CAA Sectionsection 111(b)(1)(A). Following that listing, the EPA “shall publish proposed regulation s, establishing federal standards of performance for n ew sources within such category” and then “promulgate

.... . . such standards” within a year after proposal. SectionCAA section 111(b)(1)(B). The EPA “may distinguish among classe s, types, and sizes within categories of new sources for the purp ose of establishing such standards.” SectionCAA section 111(b)(2). The term “standard of performance” is defined to “mean[ ] a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the applicat ion of the

rulesrulemakings are generally consistent with each other except to the extent that they reflect distinctions betwee n new and existing sources. For example, as discussed below, the legislative history indicates that Congress intende d that the BSER for new industrial facilities, which wereare expected to have lengthy useful lives, wouldshould include , at a minimum, the most advanced pollution controls available, but Congress had a broader conception of BSER for existing facilitiessources, the additional costs of retrofit may render those contr ols too expensive

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 155 of 854 best system of emission reduction which (taking int o account the cost of achieving such reduction and any nonairnon-air quality health and environmental impact and energy requirem ents) the Administrator determines has been adequately demons trated.” SectionCAA section 111(a)(1). As noted in the January 2014 proposal, Congress fir st included the definition of “standard of performance ” when enacting CAA section 111 in the 1970 Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and then amend ed it again in the 1990 CAAA to largely restore the definition as it read in the 1970 CAAA. It is in the legislative history for the 1970 and 1977 CAAAs that Congress primarily addressed the de finition as it read at those times , and that legislative history provides guidance in interpreting this provision. 127 In addition, the D.C.

127 In the 1970 CAAA, Congress defined “standard of pe rformance,” under §111(a)(1), as— a standard for emissions of air pollutants which reflects the degree of emission limitation achievab le through the application of the best system of emiss ion reduction which (taking into account the cost of achieving such reduction) the Administrator determi nes has been adequately demonstrated. In the 1977 CAAA, Congress revised the definition t o distinguish among different types of sources, and t o require that for fossil fuel-fired sources, the standard : (i) be based on, in lieu of the “best system of emission reducti on .... . . adequately demonstrated,” the “best technological s ystem of continuous emission reduction

.... . . adequately demonstrated;” and (ii) require a percentage reduction in emission s. In*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 156 of 854 Circuit has reviewed rulemakings under CAA section 111 on numerous occasions during the past 40 years, handin g down decisions dated from 1973 to 2011, 128 through which the Court has developed a body of case law that interprets the te rm “standard of performance.” 3. Key Elements of Interpretation By its terms, the definition of “standard of perfor mance”

under CAA [ section ] 111(a)(1) provides that the emissionsemission limits that the EPA promulgates must be

addition, in the 1977 CAAA, Congress expanded the p arenthetical requirement that the Administrator consider the cos t of achieving the reduction to also require the Adminis trator to consider “any nonair quality health and environment impact and energy requirements.” In the 1990 CAAA, Congress again revised the defini tion, this time repealing the requirements that the stand ard of performance be based on the best technological syst em and achieve a percentage reduction in emissions, and re placing those provisions with the terms used in the 1970 CAAA ver sion of §111(a)(1) that the standard of performance be base d on the “best system of emission reduction

.... . . adequately demonstrated.” This 1990 CAAA version is the curre nt definition , which is applicable at present . Even so, because parts of the definition as it read under the 1977 C AAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative history, and the interpretation in the case law, of those parts of the definition in the case law remai n relevant to the definition as it reads today. 128 Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, (D.C. Cir. 1973); Portland Cement Ass’n v. EPA , 665 F.3d 177 (D.C. Cir. 2011). See also Delaware v. EPA , No. 13-1093 (D.C. Cir. May 1, 2015).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 157 of 854 “achievable” by application of a “ system of emission reduction ” that the EPA determines to be the “best system ” that is “adequately demonstrated,” “taking into account ... c ost ... nonair quality health and environmental impact and energy requirements.” The D.C. Circuit has stated that , in determining the “best” system, the EPA must also take into acco unt “the amount of air pollution” 129 reduced and the role of “technological innovation.” 130 The Court has emphasized that the EPA has discretion in weighing those various factor s. 131,132 We discuss each of these elements below. a. Achievability of Our overall approach to determining the standard of emissions. In BSER, which incorporates the January 2014 proposal various elements, is as follows: First , the EPA recognized identifies the “system[s] of emission reduction” that the first element of the definition of “standard of per formance” is that “the emission limit [ i.e ., the ‘standard for emissions’] that the EPA promu lgates must be

129 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981). 130 See Sierra Club v. Costle, 657 F.2d at 347. 131 See Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999). 132 Although section 111(a)(1) may be read to state th at the factors enumerated in the parenthetical are part of the “adequately demonstrated” determination, the D.C. C ircuit’s case law appears to treat them as part of the “best” det ermination. See Sierra Club v. Costle, 657 F.2d at 325-26. It does not appear that those two approaches would lead to diff erent outcomes. In this rule, the EPA is following the D. C. Circuit case law and treating the factors as part of the “b est” determination. Formatted: Font: +Body (Calibri), 11 pt, No underline*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 158 of 854 ‘achievable’” based on performance of the BSER. have been “ 79 FR 1430, 1463 (January 8, 2014). A standard of performance is “achievable” if a techno logy can reasonably be projected to be available to new sour ces at the time they are constructed that will allow them to m eet the

standard. 133 Some commenters stated that the EPA’s analysis of t he requirements for “standard of performance,” includi ng the BSER, attempted to eliminate the requirement that the sta ndard for emissions must be “achievable.” We disagree with th is comment. As just quoted, the EPA’s analysis recognizes that the standard for emissions must be achievable through the applic ation of the BSER. In sections below, we show both that for new, modified, and reconstructed steam generators and combustion t urbines, each BSER that we identify is technically feasible and adequately

demonstrated , considering cost, nonair quality” for a particula r source category. Second, the EPA determines the “be st” of these systems after evaluating extent of emission reducti ons, costs, any non-air health and environmental impactimpacts, and energy requirements ; and that each of the standards for emissions that we promulgate is achievable. And third, the EPA sel ects an achievable standard for emissions - here, the emiss ion rate - based on the performance of the BSER. The remainder of this

133 See Portland Cement v. Ruckelshaus , 486 F. 2d 375, 391 (D.C. Cir. 1973).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 159 of 854 subsection discusses the various elements in that a nalytical approach

. a. “System[s] of emission reduction ... adequately demonstrated”

b. The EPA’s first step is to identify “system[s] of e mission reduction ... adequately demonstrated.” For the rea sons discussed below, for the various types of newly con structed, modified, and reconstructed sources in this rulemak ing, the EPA focused on efficient generation, add-on controls, e fficiency improvements, and clean fuels as the systems of emi ssion reduction. An “adequately demonstrated” system, according to t he D.C. Circuit, is “one which has been shown to be reasona bly reliable, reasonably efficient, and which can reasonably be e xpected to serve the interests of pollution control without be coming exorbitantly costly in an economic or environmental way.” 134 It does not mean that the system “must be in actual ro utine use

somewhere.” 135 Rather, the Court has said, “[t]he Administrator may make a projection based on existing technology, though that

134 Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), cert. denied , 416 U.S. 969 (1974). 135 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted) (discussing the Sena te and House bills and reports from which the language in CAA se ction 111 grew).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 160 of 854 projection is subject to the restraints of reasonab leness and cannot be based on ‘crystal ball’ inquiry.” 136 Similarly, the EPA may “hold the industry to a standard of improved de sign and operational advances, so long as there is substanti al evidence that such improvements are feasible.” 137 Ultimately, the analysis “is partially dependent on ‘lead time,’” that is, “ the time in which the technology will have to be available.” 138 Per CAA section 111(e), standards of performance under CAA section 111(b) are applicable immediately after the effecti ve date of their promulgation

(1) Technical feasibility of the best system of emissi on reduction

. As the January 2014 proposal indicates, the require ment that the standard for emissions be “achievable” bas ed on the “best system of emission reduction ... adequately d emonstrated” indicates that one of the requirements for the tech nology or other measures that the EPA identifies as the BSER is that the measure must be technically feasible. See 79 FR 143 0, 1463 (January 8, 2014). c. Amount of emissions reductions. In the January 2 014 proposal,

136 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 137 Sierra Club v. Costle , 657 F.2d 298, 364 (1981). 138 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 161 of 854 we noted that although the definition of “standard of performance” does not by its terms identify the amo unt of emissions from the category of sources or the amoun t of emission reductions achieved as factors the EPA must conside r in determining the “best system of emission reduction, ” the D.C. Circuit has stated that the EPA must do so. See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can think of no sens ible interpretation of the statutory words “best ... system” which would not incorporate the amount of a ir pollution as a relevant factor to be weighed when determining the optimal standard for controlli ng ... emissions”). 139 The fact that the purpose of a “system of emission reduction” is to reduce emissio ns, and that the term itself explicitly incorporate s the concept of reducing emissions, supports the Cou rt’s view that in determining whether a “system of emission reduction” is the “best,” EPA must consider the amount of emission reductions that the system would yield. Even if the EPA were not required to consider the amount of emission reducti ons, the EPA has the discretion to do so, on grounds that either the term “system of emission” or the term “best” may reasona bly be read

under Chevron step 2 to allow that discretion

139 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was governed by the 1977 CAAA version of the definition of “standard of performance,” which revised the phrase “best sys tem” to read, “best technological system.” As noted above, the 1990 CAAA deleted “technological,” and thereby returned the p hrase to how it read under the 1970 CAAA. The court’s interpreta tion of this phrase in Sierra Club v. Costle to require consideration of the amount of air emissions reductions remains valid fo r the phrase “best system.”*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 162 of 854 d.b. “Best” In determining which adequately demonstrated system of emission reduction is the “best,” the EPA considers the following factors: (1) Costs . Under CAA section 111(a)(1), the EPA is required to take into account “the cost of achieving” the required e mission reductions. As described in the January 2014 propos al, 140 in several cases the D.C. Circuit has elaborated on th is cost factor and formulated the cost standard in various ways, stating

that the EPA may not adopt a standard the cost of which woul d be “exorbitant,” 141 “greater than the industry could bear and survive,” 142 “excessive,” 143 or “unreasonable.” 144 These formulations appear to be synonymous, and for conve nience, in this rulemaking, we will use reasonableness as the standard, so that a control technology may be considered the “be st system of emission reduction ... For convenience, in this rul emaking, we use ‘reasonableness’ to describe costs well within the bounds established by this jurisprudence adequately demonstrated” if its

140 79 FR 1430, 1464 (January 8, 2014). 141 Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999). 142 Portland Cement Ass’n v. EPA , 513 F.2d 506, 508 (D.C. Cir. 1975). 143 Sierra Club v. Costle , 657 F.2d 298, 343 (D.C. Cir. 1981). 144 Sierra Club v. Costle , 657 F.2d 298, 343 (D.C. Cir. 1981).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 163 of 854 costs are reasonable, but cannot be considered the best system if its costs are unreasonable

. 145 The D.C. Circuit has never invalidated a standard of performance on groundsindicated that it was too costly.the EPA has substantial discretion in its consideration of cost under section 111(a). In several cases, the Court upheld standards

145 These cost formulations are consistent with the le gislative history of section 111. The 1977 House Committee Re port noted: In the [1970] Congress [sic: Congress’s] view, it w as only right that the costs of applying best practica ble control technology be considered by the owner of a large new source of pollution as a normal and proper expe nse of doing business. 1977 House Committee Report at 184. Similarly, the 1970 Senate Committee Report stated:

The implicit consideration of economic factors in determining whether technology is “available” shoul d not affect the usefulness of this section. The overridi ng purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of thei r construction is seen by the committee as the most effective and, in the long run, the least expensive approach. S. Comm. Rep. No. 91-1196 at 16. Some commenters asserted that we do not have authority to revise the cost standar d as established in the case law, e.g., “exorbitant,” “e xcessive,” etc., to a “reasonableness” standard that may be co nsidered less protective of the environment. We agree that we do not have authority to revise the cost standard as establishe d in the case law, and we are not attempting to do so here. Rathe r, our description of the cost standard as “reasonableness ” is intended to be a convenient term for referring to the cost s tandard as established in the case law.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 164 of 854 that entailed significant costs, consistent with Co ngress’s view that “the costs of applying best practicable contro l technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business.” 146 See Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, 440 (D.C. Cir. 1973); 147 Portland Cement Association v. Ruckelshaus , 486 F.2d 375, 387-88 (D.C. Cir. 1973); Sierra Club v. Costle , 657 F.2d 298, 313 (D.C. Cir. 1981) (upholding standard impos ing controls

on SO 2 emissions from coal-fired power plants when the ”c ost of

the new controls ... is substantial”).is substantial”). 148 Moreover, section 111(a) does not provide specific direction regarding what metric or metrics to use in consider ing costs, again affording the EPA considerable discretion in choosing a means of cost consideration. 149

146 1977 House Committee Report at 184. 147 The costs for these standards were described in th e rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 (March 21, 1972). 148 Indeed, in upholding the EPA’s consideration of co sts under the provisions of the Clean Water Act authorizing t echnologybased standards based on performance of a best tech nology taking costs into account, courts have also noted the subs tantial discretion delegated to the EPA to weigh cost consi derations with other factors. Chemical Mfr’s Ass’n v. EPA , 870 F.2d 177, 251 (5th Cir. 1989); Association of Iron and Steel Inst. v. EPA , 526 F.2d 1027, 1054 (3d Cir. 1975); Ass’n of Pacific Fisheries v. EPA, 615 F.2d 794, 808 (9th Cir. 1980). 149 Indeed, in upholding the EPA’s consideration of cos ts under other provisions requiring consideration of cost, c ourts have also noted the substantial discretion delegated to the EPA to weigh cost considerations with other factors. Chemical Mfr’s Formatted: Font: Courier New, 12 pt*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 165 of 854 As discussed below, the EPA may consider costs on b oth a source-specific basis and a sector-wide, regional, or nationwide basis. The EPA is finding here that whether costs are con sidered on a source-specific basis, an industry/national ba sis, or both, they are reasonable. See Sections V.H and I below. e.(2) Non-air quality health and environmental impacts

. Under CAA section 111(a)(1), the EPA is required to take into account “any nonair quality health and environ mental impact” in determining the BSER and whether it is adequately demonstrated. This. As the D.C. Circuit has explain ed, this requirement makes explicit what was implicit in the initial version of section 111:that a system cannot be “best” if it does more harm than good due to cross-media environmenta l impacts. 150 The EPA has carefully considered such cross-media i mpacts here, in particular potential impacts to underground sour ces of drinking water posed by CO 2 sequestration, and water use

Ass’n v. EPA , 870 F. 2d 177, 251 (5th Cir. 1989); Association of Iron and Steel Inst. v. EPA , 526 F. 2d 1027, 1054 (3d Cir. 1975); Ass’n of Pacific Fisheries v. EPA, 615 F. 2d 794, 808 (9th Cir. 1980). See, e.g., Husqvarna AB v. EPA , 254 F.3d 195, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a spe cific method of cost analysis, the EPA may make a reasoned choic e as to how to analyze costs). 150 Portland Cement v. EPA , 486 F. 2d at 384; Sierra Club v. Costle , 657 F. 2d at 331; see also Essex Chemical Corp. v. Ruckelshaus , 486 F. 2d at 439 (remanding standard to consider solid waste disposal implications of the BSER deter mination).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 166 of 854 necessary to operate carbon capture systems. See Sections V.N

and O below. f.(3) Energy considerations

. Under CAA section 111(a)(1), the EPA is required to take into account “energy requirements.” As discussed be low, the EPA may consider energy requirements on both a source-s pecific basis and a sector-wide, region-wide, or nationwide basis . Considered on a source-specific basis, “energy requirements” entails consideringentail, for example, the amountimpact, if any, of the system of emission reduction on the source’s own energy required to run the pollution control requirements.needs. In this rulemaking, as discussed below in Section V.O.3 , the EPA considered the parasitic load requirements of parti al CCS . The EPA is finding here that whether energy requirement s are considered on a source-specific basis, an industry/ national basis, or both, they are reasonable. See Sections V .O.3 and

XIII.C . (4) Amount of emissions reductions At proposal, we noted that although the definition of “standard of performance” does not by its terms ide ntify the amount of emissions from the category of sources or the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reducti on,” the D.C. Circuit has stated that the EPA must in fact do so. See Sierra*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 167 of 854 Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can think of no sensible interpretation of the statutor y words “best ... system” which would not incorporate the amount of air pollution as a relevant factor to be weighed when d etermining the optimal standard for controlling ... emissions”). 151 The fact that the purpose of a “system of emission reduction ” is to reduce emissions, and that the term itself explicit ly incorporates the concept of reducing emissions, sup ports the Court’s view that in determining whether a “system of emission reduction” is the “best,” g.the EPA must consider the amount of emission reductions that the system would yield. 152 Even if the EPA were not required to consider the amount of emi ssion reductions, the EPA has the discretion to do so, on grounds that either the term “system of emission reduction” or t he term “best” may reasonably be read to allow that discret ion. (5) Sector

- or nationwide component of factors in determining the BSER . factors

151 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was governed by the 1977 CAAA version of the definition of “standard of performance,” which revised the phrase “best sys tem” to read, “best technological system.” As noted above, the 1990 CAAA deleted “technological,” and thereby returned the p hrase to how it read under the 1970 CAAA. The court’s interpreta tion of this phrase in Sierra Club v. Costle to require consideration of the amount of air emissions reductions remains valid fo r the phrase “best system.” 152 See also NRDC v. EPA , 479 F. 3d 875, 880 (D.C. Cir. 2006) (“best performing” source for purposes of CAA secti on 112 (d)(3) is source with the lowest emission levels).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 168 of 854 As discussed in the January 2014 proposal, another component of the D.C. Circuit’s interpretations of CAA section 111 is that the EPA may consider the various factor s it is required to consider on a national or regional leve l and over time, and not only on a plant-specific level at the time of the rulemaking. 153 The D.C. Circuit based this conclusion on a review of the legislative history, stating,

The Conferees defined the best technology in terms of “long-term growth,” “long-term cost saving s,” effects on the “coal market,” including prices and utilization of coal reserves, and “incentives for improved technology.” Indeed, the Reports from both Houses on the Senate and House bills illustrate ver y clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmen tal and energy effects of different technological syste ms when it discussed section 111. 154

The Court has upheld EPA rules that the EPA “justified ... in terms of the policies of the Act,” including balanc ing long-term national and regional impacts:

The standard reflects a balance in environmental, economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO 2 emissions (3 million tons in 1995) yet does so at reasonable costs without significant energy penalties.... By achieving a balanced coal demand within the utility sector and by promoting t he development of less expensive SO 2 control technology, the final standard will expand environmentally

153 79 FR 1430, 1465 January 8, 2014) (citing Sierra Club v. Costle , 657 F.2d at 351). 154 Sierra Club v. Costle , 657 F.2d at 331 (citations omitted) (citing legislative history).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 169 of 854 acceptable energy supplies to existing power plants and industrial sources. By substantially reducing SO 2 emissions, the standard will enhance the potential for long term economic growth at both the national and regional levels. 155 Some commenters objected that this case law did not excuse the EPA from justifying costs and energy considerat ions on the basis of theirallow the EPA to ignore source-specific impacts , but rather, required the EPA to justify costs and e nergy considerations on both (particularly cost impacts) by basing determinations solely on impacts at a regional or national level. In fact, the EPA’s consideration of cost, no n-air quality impacts, and energy requirements reflect source-specific basis and aimpacts, as well as (for some considerations) impacts that

are sector-wide, regional, or national basis. The EPA has in fact done so here, as discussed. See Section V.H.6 below. h. Expanded use and developmentc. Achievability of the Standard for Emissions In the January 2014 proposal, the EPA recognized th at the first element of the definition of “standard of per formance” is that “the emission limit [ i.e ., the ‘standard for emissions’]

155 Sierra Club v. Costle , 657 F.2d at 327-28 (quoting 44 Fed. Reg. at 33,583FR 33583 /3 - 33,58433584 /1). In the January 2014 proposal, we explained that although the D.C. Circu it decided Sierra Club v. Costle before the Chevron case was decided in 1984, the D.C. Circuit’s decision could be justifie d under either Chevron step 1 or 2. 79 FR 1430, 1466 (January 8, 2014).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 170 of 854 that the EPA promulgates must be ‘achievable’” base d on performance of the BSER. 79 FR 1430, 1463 (January 8, 2014). According to the D.C. Circuit, a standard for emiss ions is “achievable” if a technology . can reasonably be projected to be available to new sources at the time they are const ructed that will allow them to meet the standard. 156 Moreover, according to the Court, ”[a]n achievable standard is one which i s within the realm of the adequately demonstrated system’s effic iency and which, while not at a level that is purely theoreti cal or experimental, need not necessarily be routinely ach ieved within the industry prior to its adoption.” 157 To be achievable, a standard “must be capable of being met under most a dverse conditions which can reasonably be expected to recu r and which are not or cannot be taken into account in determin ing the ‘cost of compliance.’” 158 To show that a standard is achievable, the EPA must “(1) identify variable conditions that mig ht contribute to the amount of expected emissions, and (2) establ ish that the

156 Portland Cement , 486 F.2d at 391-92. Some commenters stated that the EPA’s analysis of the requirements for “st andard of performance,” including the BSER, attempted to elim inate the requirement that the standard for emissions must be “achievable.” We disagree with this comment. As jus t quoted, the EPA’s analysis recognizes that the standard for emi ssions must be achievable through the application of the BSER. 157 Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 433-34 (D.C. Cir. 1973), cert. denied , 416 U.S. 969 (1974). 158 Nat’l Lime Ass’n v. EPA , 627 F.2d 416, 433, n.46 (D.C. Cir. 1980).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 171 of 854 test data relied on by the agency are representativ e of potential industry-wide performance, given the rang e of variables that affect the achievability of the stan dard.” 159 In Sections V.J and IX.D below, we show both that t he BSER for new steam generating units and combustion turbi nes is technically feasible and adequately demonstrated, a nd that the standards of 1,400 lb CO 2 /MWh-g and 1,000 lb CO 2 /MWh-g are achievable considering the range of operating varia bles that affect achievability. d. Expanded Use and Development of Technology In the January 2014 proposal, we noted that the D.C

. Circuit has made clear that Congress intended for C AA section 111 to create incentives for new technology and the refore that

the EPA is required to consider technological innovatio n as one of the factors in determining the “best system of e mission reduction.” 160

159 Sierra Club v. Costle , 657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat’l Lime Ass’n v. EPA , 627 F.2d 416 (D.C. Cir. 1980). In considering the representativeness of the source tested, the EPA may consider such variables as the “‘feedstock, operation, size and age’ of the source.” Nat’l Lime Ass’n v. EPA , 627 F.2d 416, 433 (D.C. Cir. 1980). Moreover, it may be suff icient to “generalize from a sample of one when one is the on ly available sample, or when that one is shown to be representat ive of the regulated industry along relevant parameters.” Nat’l Lime Ass’n v. EPA , 627 F.2d 416, 434, n.52 (D.C. Cir. 1980). 160 See 79 FR 1430, 1465 (January 8, 2014), Sierra Club v. Costle , 657 F.2d at 346-47.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 172 of 854 The Court grounded its reading in the statutory tex t. 161 We addedIn addition, in the January 2014 proposal, we noted that the Court’s interpretation finds firmadditional support as well in the legislative history , and. 162 We also explained that the legislative history identifies three different ways that Congress designed CAA section 111 to authorize stan dards of performance that promote technological improvement: (i) the development of technology that may be treated as th e “best system of emission reduction . . . adequately demon strated ;”” under section 111(a)(1); (ii) the expanded use of t he best demonstrated technology; and (iii) the development of emerging technology. 163 Even if the EPA were not required to consider technological innovation as part of its determinati on of the BSER, it would be reasonable for the EPA to conside r it, either

161 Sierra Club v. Costle , 657 F. 2d at 346 (“Our interpretation of section 111(a) is that the mandated balancing of cost, energy, and nonair quality health and environmental factors embraces consideration of technological innovation as part of that balance. The statutory factors which the EPA must weigh are broadly defined and include within their ambit subf actors such as technological innovation.”).

. 162 See 79 FR 1430, 1465 (January 8, 2014) (citing S.Rep. 91-1196 at 16 (1970)) (“Standards of performance should pro vide an incentive for industries to work toward constant im provement in techniques for preventing and controlling emissions from stationary sources”); S. Rep. 95-127 at 17 (1977) ( cited in Sierra Club v. Costle , 657 F.2d at 346 n. 174) (“The section 111 Standards of Performance ... sought to assure the u se of available technology and to stimulate the developme nt of new technology”). 163 79 FR at 1465 (citing case law and legislative history).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 173 of 854 because technological innovation may be considered an element of the term “best,” or because the term “best system o f emission reduction” is ambiguous as to whether technological innovation may be considered , and it is reasonable for the EPA to interpret it to authorize consideration of technological inno vation in light of Congress’s emphasis on technological innov ation.. The interpretation is likewise consistent with the evid ent purpose of section 111(b) to require new sources to maximiz e emission reductions using state-of-the-art means of control.

Commenters statestated that the requirement to consider technological innovation does not authorize the EPA to identify as the BSER a technology that is not adequately dem onstrated. The proposal did not, and we do not in this final r ule, claim to the contrary. In any event, as discussed below, the EPA may justify the control technologies identified in this rule as the BSER even without considering the factor of incenti vizing technological innovation or development. ie . Agency discretion. Discretion As discussed in the January 2014 proposal, the D.C. Circuit has made clear that the EPA has broad discretion in determining the appropriate standard of performance under the d efinition in CAA section 111(a)(1), quoted above. Specifically, in Sierra

Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981), the Court explained that “section 111(a) explicitly instructs the EPA to*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 174 of 854 balance multiple concerns when promulgating a NSPS, ” 164 and emphasized that “[t]he text gives the EPA broad dis cretion to weigh different factors in setting the standard.” 165 In Lignite Energy Council v. EPA , 198 F.3d 930 (D.C. Cir. 1999), the Court reiterated:

Because section 111 does not set forth the weight that should be assigned to each of these factors, w e have granted the agency a great degree of discretio n in balancing them.... EPA's choice [of the ‘best system’ ] will be sustained unless the environmental or econo mic costs of using the technology are exorbitant.... EPA [has] considerable discretion under section 111. 166 jf . Lack of requirementRequirement that standard be able to be

metStandard Must Be Met by all sources. All Sources In the January 2014 proposal, the EPA proposed that

, under CAA section 111, an emissions standard may me et the requirements of a “standard of performance” even if it cannot be

164 Sierra Club v. Costle , 657 F.2d at 319. 165 Sierra Club v. Costle , 657 F.2d at 321; see also New York v. Reilly, 969 F. 2d at 1150 ( because Congress did not assign the specific weight the Administrator should assign to the statutory elements, “the Administrator is free to exercise [h er] discretion” in promulgating an NSPS .). 166 Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999) (paragraphing revised for convenience). S ee also NRDC v. EPA , 25 F.3d 1063, 1071 (D.C. Cir. 1994) (The EPA did not err in its final balancing because “neither RCRA nor EPA’s regulations purports to assign any particular weight to the fac tors listed in subsection (a)(3). That being the case, the Adm inistrator was free to emphasize or deemphasize particular fac tors, constrained only by the requirements of reasoned ag ency decision making.”).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 175 of 854 met by every new source in the source category that would have constructed in the absence of that standard. As des cribed in the January 2014 proposal, the EPA based this view on ( i) the legislative history of CAA section 111, read in con junction with the legislative history of the CAA as a whole; (ii) case law under analogous CAA provisions; and (iii) long-stan ding precedent in the EPA rulemakings under CAA section 111. 167 Commenters contested this assertion, arguing that a 111(b) standard must be achievable by all new sources. We continue to take the same position we took in the proposed rulemakingas at proposal for the reasons described there. We note that as a practical matter, in this rulemaking, the issue of whether all new steam-generating sources can implement partial- capture CCS is largely dependent on the geographic scope of geologic sequestration sites. As discussed below , in Section V.M, geologic sequestration sites are widely available, and a st eamgenerating plant with partial CCS that is sited nea r an area withthat is suitable for geologic sequestration sites available can serve demand in a large area that may not have sequestration sites available. In any event, the standard of 1,400 lb CO 2 /MW standard-g that we promulgate in this final rule can be achieved by coal-fired power plantsnew steam generating EGUs – including

167 79 FR 1430, 1466 (January 8, 2014).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 176 of 854 new utility boilers and IGCC units - through co-firing with natural gas in lieu of installing partial -capture CCS, which moots the issue of the geographic availability of CCS. geologic sequestration. g. EPAct05

k. EPAct05. The Energy Policy Act of 2005 (“EPAct05”) authorize s assistance in the form of grants, loan guarantees, as well as Federal federal tax credits for investment in “ clean coal technology

. .” Sections 402( i), 421( a), 402(i), 1307 (b), and 1307(b) (adding section 48A(g)

to the Internal Revenue Code (“ IRC ) ”)) address the extent to which information from clean coal projects receiving assistance under the EPAct05 may be consi dered by the EPA in determining what is the best system of emission reduction adequately demonstrate d. Section 402(i) of the EPAct05 limits the use of information from facilities that receive assistance under EPAct05 in CAA section 111 rulemakings: “No technology, or level of emission reduction, sol ely by reason of the use of the technology, or the achieve ment of the emission reduction, by 1 or more facilities receivi ng assistance under this Act, shall be considered to be adequatel y demonstrated [] for purposes of section 111 of the Clean Air Act

....” 168

168 Codified at 42 U.S.C. 15962(a). EPAct05 section 42 1(a) includes a similar constraint. Codified at 42 U.S.C . 15962(a). EPAct05 section 421(a) similarly states: “No techno logy, or level of emission reduction, shall be treated as ad equately demonstrated for purpose [sic] of section 7411 of t his title, ...*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 177 of 854 IRC section 48A(g) contains a similar constraint co ncerning the use of technology ofor level of emission reduction from electric generating unitEGU facilities for which a tax credit is

allowed: “No use of technology (or level of emission reducti on solely by reason of the use of the technology), and no achievement of any emission reduction by the demonstration of any technology or performance leve l, by or at one or more facilities with respect to whi ch a credit is allowed under this section, shall be considered to indicate that the technology or performance level is adequately demonstrated [] for purposes of section 111 of the Clean Air Act .....”.....”

The EPA specifically solicited comment on its interpretation of these provisions. 79 FR 10750 (Fe b. 26, 2014)(Notice of Data Availability). With respect to EPAct05 sectionsections 402(i) and 421 (a), the EPA proposed that these provisions barred consideration where EPAct05 assistanceassisted facilities were the sole support offor the BSER determination, but EPAct05that these sources could support a BSER determination so long as there is additional e vidence supporting the determination. 169 In addition, the EPA viewed the prohibitiontwo prohibitions as relating only to the technology

solely by reason of the use of such technology, or the achievement of such emission reduction, by one or m ore facilities receiving assistance under section 13572 (a)(1) of this title”. 169 Technical Support Document p. 6.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 178 of 854 or emissions reduction for which assistance was giv en. 170 The EPA likewise interpreted IRC section 48A(g) – based on the plain language and the context provided by sections 402(i ) and 421(a)

– to mean that use of technology, or emission perform ance, from a facility for which the credit is allowed cannot, by itself, support a finding that the technology or performanc e level is adequately demonstrated, but the information can co rroborate an otherwise supported determination or otherwise prov ide part of the basis for such a determination. 171 The EPA also proposed the interpretation thatto interpret the phrase “with respect to which a credit is allowed under this section” refersas referring to the entire phrase “use of technology (or level o f emission reduction ...) and ......[] achievement of any emission reduction..., by or at one or more facilities.” Thus, if technology A received a tax credit, but technology B at the same facility d id not, the constraint would not apply to technology B. 172 Some commenters supported the EPA’s proposed interpretation. Others challenged a reading wherebycontended that the EPA’s interpretation would allow it to sup port a BSER determination even where EPAct05 facility information could comprisecomprised 99 percent of the supporting information for a

170 Id. 171 Id. p. 13. 172 Id. p. 14.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 179 of 854 BSER determination , but could be considered because thethat determination waswould not be based “solely” on EPAct05 sources. They These commenters urged a reading that the EPA could consider to conclude that a determination “solely” on the basis

of information from projects funded under the EPAct05 only if, without -assisted facilities is any determination w here “but

for” that information, the EPA could not justify its chosen

standard as the BSER – in other words, a “but for” test. 173

Some. 174 Other commenters argued that the provisions simply requiredbar the EPA to rely only upon non-from all consideration

of EPAct05 facilities to support a determination when determining that a technology or level of performance is adequately demonstrated. 175 In this final rule, the EPA is adopting the interpr etations

of bothall three provisions that it proposed, largely for the reasons previously advanced. The EPA thus interpret s these provisions to preclude the EPA from relying solely on the experience of facilities that received DOE assistan ce, but not to preclude the EPA from relying on the experience of such facilities in conjunction with other information. T his reading

173 Comments of AFPM/API p. 46. 174 Comments of AFPM/API p. 46. 175 One commenter supported its reading by adding sugg ested text to the statutory language, a highly disfavored form of statutory construction. Comments of UARG p. 124 n. 38.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 180 of 854 of sections 402(i) and 421 (a) is consistent with the views of the only court to date to consider the matter. 176

The EPA also notes that the extreme example providedhypothetical posed in the comments ( reading “solely” to allow where the EPA might avoid a limitation on its consideration of EPAct05 sources to be the overwhelming basis for a determination that-assisted facilities by inc luding a technology or level of performance is adequately demonstratedmere scintilla of evidence from non-EPA ct05 facilities ) is not presented here, where the principal eviden ce that partial post-combustion CCS is a demonstrated and feasible technology comes from sources which received no ass istance of any type under EPAct05. This evidence satisfies the “but for” construction urged by these commenters.The EPA also concludes that the “but for” test urged by these commenters i s an inappropriate reading of the term “solely” in secti ons 402(i) and 421(a), as any piece of evidence may be a neces sary, or “but

176 State of Nebraska v. EPA , 2014 U.S. Dist. LEXIS 141898 at n. 1 (D. Nebr. 2014). (“But the Court notes that § 402 (i) only forbids the EPA from considering a given technology or level of emission reduction to be adequately demonstrated solely on the basis of federally-funded facilities. 42 U.S.C. § 1 5962(i). In other words, such technology might be adequately de monstrated if that determination is based at least in part on non -federallyfunded facilities”)(emphasis original).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 181 of 854 for,” cause without being a sufficient, or “sole,” cause. 177 Nonetheless, if the “but for” test were applicable here, the available evidence would satisfy it. CertainOther commenters took the extreme position that

thesethe EPAct05 provisions bar all consideration even of facilities’a facility’s existence if the facility received EPAct05 assistance. 178 The EPA does not accept this argument because it is contrary to both the plain statutory language 179 (see Chapter 2 of the Response-to-Comment document) and to Congress’s intent that these facilities’ experience cannot be considered as an example of first-of-a-kind sothe E PAct05 programs advance the commercialization of clean coa l technology. For the same reason, the EPA does not accept some c ommenters’ suggestion that latersections 402(i), 421(a), and 48A(g)

177 For example, any vote of a Justice on the Supreme Court may be a necessary but not sufficient cause. In a 5-4 d ecision, the decision of the Court would have been different “bu t for” the assent of Justice A or Justice B, who were in the m ajority. But it would be incorrect to say that the assent of Jus tice A was the “sole” reason for the outcome, when the decisio n also required the assent of Justice B. 178 Supplemental Comments of Murray Energy (comment 94 98) p. 11. 179 With respect to sections 402(i) and 421(a), commen ters fail to reconcile their reading of the statute with the Act’s grammatical structure, as explained in detail in ch apter 2 of the Response-to-Comment document. One commenter sup ported its reading by adding suggested text to the statutory l anguage, a highly disfavored form of statutory construction. C omments of UARG, p.124 n.38. With respect to section 48A(g), c ommenters misread the phrase “considered to indicate,” and do not explain how their reading of all three provisions together is tenable.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 182 of 854 preclude the EPA from considering NETL’s cost proje ctions for CCS, which base cost estimates on up-to-date vendor quotes reflecting costs for the CCS technology being utili zed at the Boundary Dam Unit #3 facility (a facility receiving no assistance under EPAct05), but also considers that to-be -built plants cannot be considered to learn at all from the EPAct 05 facilities’ experience.will no longer be first-of-a kind. See generally Section V .I.2 below. The EPA does not accept this argument. The EPAct05 Commenters suggest that the E PAct05 requires that the EPA treat future plants as “first of a kind” when projecting costs, as if EPAct05 facilities sim ply did not exist. This reading is contrary to the text of the provisions relate to , which as noted, relates specifically to a source’s performance and operation ( whether a technology is demonstrated, and the level of performance achieved by use of tec hnology

. These provisions thus relate in some way to an EPAc t05 source’s performance and operation. Merely acknowledging), n ot to sources’ existence. NETL’s cost projections, on the other hand, merely acknowledge the evident fact of the source’s existence is none of these. Moreover, these same commenters refe rred to these same plants in their other comments as examples of high costs of CCS technology. If therethat CCS technologies exist , and reasonably project that they will continue to devel op. See Section V.I.2. The NETL cost estimates, moreover, a re based on*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 183 of 854 vendor quotes for the CCS technology in use at the Boundary Dam facility, a Canadian plant which obviously is an absolute prohibition on considering information from EPAct05 facilities, then these plants’ costs to date also cannot be con sidered. EPA also does not agree that these commenters could sub mit comments citing not a recipient of EPAct05 facilities’ experience to support their contentions but that the EPA is barre d from responding.assistance. See sections V.D.2.a and V. I.2 below. In any case, as shown in Section V below, the EPA f inds

that a new highly-efficient SCPC EGU implementing partial postcombustion CCS is the best system of emission reduction adequately demonstrated and is doing so based in gr eater part on performance of facilities receiving no assistance u nder EPAct05, and on other information likewise not having any co nnection to EPAct05 assistance. The corroborative information f rom EPAct05 facilities, though supportive, is not necessary to the EPA’s findings. I. Severability This rule has numerous components, and the EPA inte nds that they be severable from each other to the extent tha t they function separately. For example, the EPA intends t hat each set of BSER determinations and standards of performance in this rulemaking be severable from each other set. That i s, the BSER determination and standard of performance for newly constructed*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 184 of 854 fossil fuel-fired electric utility steam generating units are severable from all the other BSER determinations an d standards of performance, and the same is true for the BSER d etermination and standard of performance for modified fossil fue l-fired electric utility steam generating units, and so on. It is reasonable to consider each set of BSER determinati on and standard of performance to be severable from each o ther set of BSER determination and standard of performance beca use each set is independently justifiable and does not depend on any other set. Thus, in the event that a court should strike down any set of BSER determination and standard of performance, the remaining BSER determinations and standards of performance sh ould not be

affected. J. Certain Projects under Development In the January 2014 proposal, the EPA indicated tha t the proposed Wolverine EGU project (Rogers City, Michig an) appeared to be the only fossil fuel-fired steam generating u nit that was currently under development that may be capable of “commencing construction” for NSPS purposes at the time of the proposal. See 79 FR 1461. The EPA also acknowledged that the Wolv erine EGU, as designed, would not meet the proposed standard of 1 ,100 lb

CO 2 /MWh for new utility steam generating EGUs. The EPA proposed that, at the time of finalization of the proposed s tandards, if the Wolverine project remains under development and has not*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 185 of 854 either commenced construction or been canceled, we anticipated proposing a standard of performance specifically fo r that facility. Additional discussion of the approach can be found in the proposal or in the technical support document i n the docket entitled “Fossil Fuel-Fired Boiler and IGCC EGU Pro jects under Development: Status and Approach.” In December 2013 – after the proposed action was si gned, but before it was published – Wolverine Power Coope rative announced that it was cancelling construction of th e proposed coal-fired power plant in Rogers City, MI. 180 Therefore, we are not finalizing the proposed exclusion for that proj ect. In the January 2014 proposal, the EPA also identifi ed two other fossil fuel-fired steam generating EGU projec ts that, as currently designed, would not meet the proposed 1,1 00 lb CO 2 /MWh emissions standard — the Plant Washington project i n Georgia and the Holcomb 2 project in Kansas. We indicated that, at the time of the proposal, those projects appeared to remain under development but that the project developers had rep resented that the projects have commenced construction for NSPS p urposes and, thus, would not be new sources subject to the propo sed or final NSPS. Based solely on the developers’ representatio ns, the EPA

180 “Wolverine ends plant speculation in Rogers City”, The Alpena News, December 17, 2013. http://www.thealpenanews.com/page/content.detail/id /527862/Wolve rine-ends-plant-speculation-in-Rogers-City.html?nav =5004.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 186 of 854 indicated that those projects, if ultimately fully constructed, would be existing sources, and would thus not be su bject to the standards of performance in this final action. To date, neither developer has sought a formal EPA determination of NSPS applicability. As we specifie d in the January 2014 proposal – and we reiterate here - if such an applicability determination concludes that either t he Plant Washington (GA) project or the Holcomb 2 (KS) proje ct did not commence construction prior to January 8, 2014 (the publication of the January 2014 proposal), then the project sho uld be situated similarly to the disposition the EPA propo sed for the Wolverine project. Accordingly, the EPA is finalizi ng in this action that if it is determined that either of thes e projects has not commenced construction as January 8, 2014, then that project will be addressed in the same manner as was proposed for the Wolverine project. In public comments submitted in response to the Jan uary 2014, Power4Georgians (P4G), the Plant Washington d eveloper, reiterated that they had executed binding contracts for the purchase and erection of the facility boiler prior to publication of the January 2014 proposal and believ e that the binding contracts are sufficient to constitute comm encement of construction for purposes of the NSPS program, so t hat they are*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 187 of 854 existing rather than new sources for purposes of th is rule. 181 Public comments submitted by Tri-State Generation a nd Transmission Association and Sunflower Electric Pow er Corporation, the developers of the Holcomb 2 projec t, discussed the cost incurred in the development of the project . They also indicated they had awarded contracts for the turbin e/generator purchase and had negotiated a rail-supply agreement that provides for the delivery of fuel to the proposed H olcomb 2 site. The developers did not, however, explicitly c haracterize the construction status of the project. 182 Other groups submitted comments contending that neither project has actual ly commenced construction. In October 2013, the Kansas Supreme Court invalidat ed the 2010 air pollution permit granted to Sunflower Elec tric Power Corporation by the Kansas Department of Health and Environment (KDHE). 183 In May 2014, the KDHE issued an air quality permit addendum for the proposed Holcomb 2 coal plant. The addendum addressed federal regulations that the Kansas Supre me Court held had been overlooked in the initial permitting deter mination. In June 2014, the Sierra Club filed an appeal with the Kansas

181 Docket entry: EPA-HQ-OAR-2013-0495-9403. 182 Docket entry: EPA-HQ-OAR-2013-0495-9599. 183 “Kansas High Court Invalidates 895-MW Coal Project Air Permit”, Power Magazine, 10/10/2013, available at: www.powermag.com/kansas-high-court-invalidates-2010 -895-mw-coalproject-air-permit/.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 188 of 854 Appellate Court challenging the legality of the May 2014 permit. Since the publication of the January 2014 proposal, the EPA is unaware of any physical construction activity at th e proposed Holcomb 2 site. In October 2014, the Plant Washington project was g iven an 18-month air permit extension by the Georgia Enviro nmental Protection Division (EPD). However, as with the Hol comb expansion project, the EPA is unaware of any physic al construction that has taken place at the proposed P lant Washington site and a recent audit of the project d escribed it as “dormant”. 184 Based on this information, it appears that these so urces have not commenced construction for purposes of sec tion 111(b) and therefore would likely be new sources should th ey actually be constructed. As noted above, the EPA proposed th at, if these projects are determined to not have commenced const ruction for NSPS purposes prior to the publication of the propo sed rule, they will be addressed in the same manner proposed for the Wolverine project. 79 FR 1461. We are finalizing th at proposal here. However, because these units may never actual ly be fully built and operated, we are not promulgating a stand ard of

184 http://www.macon.com/2015/06/23/3811798/audit-sand ersvillecoal-plant.html.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 189 of 854 performance at this time because such action may pr ove to be

unnecessary. 185 There is one possible additional new EGU, the Two E lk project in Wyoming. In a supporting TSD accompanyin g the January 2014 proposal, we discussed the Two Elk project and relied on developer statements and state acquiescence that th e unit had commenced construction for NSPS purposes before Jan uary 8, 2014. 186 We did not, therefore, propose any special section 111(b) standard for the project. Some commenters ma intained that a continuous program of construction at the facilit y has not been maintained and that if the plant is ultimately constructed, it should be classified as a new source under CAA s ection 111(b). These comments were not specific enough to change the EPA’s view of the project for purposes of this rule making. We

185 In the proposed emission guidelines for existing E GUs, the EPA did not include estimates of emissions for eith er Plant Washington or the Holcomb 2 unit in baseline data u sed to calculate proposed state goals for Georgia and Kans as. It appears that the possibility of these plants actual ly being built and operating is too remote. If either unit e ventually seeks an applicability determination and that unit is determined to be an existing source, and there is reliable evi dence that the source will operate, then the source will be su bject to the final 111(d) rule and the EPA will allow the state to adjust its state goal to reflect adjustment of the state’s bas eline data so as to include the unit. Guidance for adjustment of state goals is provided in the record for the EPA’s final CAA s ection 111(d) rulemaking. 186 “Fossil Fuel-Fired Boiler and IGCC EGU Projects Un der Development: Status and Approach”, Technical Suppor t Document at pp. 10-1 Docket Entry: EPA-HQ-OAR-2013-0495-0024.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 190 of 854 accordingly continue to rely on developer statement s that this facility has commenced construction and would not b e a new source for purposes of this proceeding. IV. Summary of Final Standards for Newly Constructe d, Modified, and Reconstructed Fossil Fuel-fired Electric Utilit y Steam Generating Units This section sets forth the standards for newly constructed, modified, and reconstructed steam gene rating units (i.e., utility boilers and IGCCs). We explain the r ationale for the final standards in Sections V (newly constructe d steam generating unit), VI (modified steam generating uni ts), and VII (reconstructed steam generating units). A. Applicability Requirements and Rationale We generally refer to fossil fuel-fired electric ut ility generating units that would be subject to an emissi on standard in this rulemaking as “affected” or “covered” sourc es, units, facilities or simply as EGUs. These units meet both the definition of “affected” and “covered” EGUs subject to an emission standard as provided by this rule, and the criteria for being considered “new,” “modified” or “reconstructe d” sources as defined under the provisions of CAA section 111 and the EPA’s regulations. This section discusses applicability f or newly constructed, modified, and reconstructed steam gene rating units.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 191 of 854 1. General Applicability Criteria The EPA is finalizing applicability criteria for ne w, modified, and reconstructed electric utility steam generating units (i.e., utility boilers and IGCC units) in 40 CFR part 60 , subpart TTTT that are similar to the applicability criteria for those units in 40 CFR part 60, subpart Da (utility boiler and IGCC performance standards for criteria pollutants) , but with some differences. The proposed applicability criter ia, relevant

comments , and final applicability criteria specific to newly constructed, modified, and reconstructed steam gene rating units are discussed below. The applicability requirements in the proposal for newly constructed EGUs included that a utility boiler or IGCC unit must: (1) be capable of combusting more than 250 MM Btu/h heat input of fossil fuel; (2) be constructed for the pu rpose of supplying, and actually supply, more than one-third of its potential net- electric output capacity to any utility power distribution system (that is, to the grid) for sale on an annual basis ,; (3) be constructed for the purpose of supplying, a nd actually supply, more than 219,000 MWh net-electric output to the grid on an annual basis; and (4) combust over 1 0 percent fossil fuel on a heat input basis over a 3-year ave rage. At proposal, applicability was determined based on a c ombination of design and actual operating conditions that could c hange*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 192 of 854 annually depending on the proportion and the amount of electricity actually sold and on the fossil proportion of the fuelfossil fuels combusted by the unit. In the proposal for modified and reconstructed EGUs , we proposed a broader applicability approach such that applicability would be based solely on design crite ria and would be identical to the applicability requirements in s ubpart Da. First, we proposed to include all utility boilers and IGCC unitselectric sales criteria that the source be constructed for the purpose of selling more than one-third of their potential electric output and more than 219,000 MWh to the gr id on an annual basis, regardless of the actual amount of el ectricity sold (i.e., we did not include the applicability cr iterion that the unit actually sell the specified amount of elec tricity on an annual basis). In addition, we proposed to include all utility boilers and IGCC facilitiesa base load rating crite rion that

arethe source be capable of combusting more than 250 MMBtu/h of fossil fuel, regardless of the actual amount of fos sil fuel burned (i.e., we did not include the applicabilityfossil fueluse criterion that an EGU actually combust more than 1 0 percent fossil fuel on a heat input basis on a 3-year avera ge). Under this approach, applicability would be known prior t o the facilityunit actually commencing operation and would not change on an annual basis. We also proposed that the final*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 193 of 854 applicability criteria would be consistent for newl y constructed, reconstructed, and modified units. The broader proposed broad applicability criteria would still not have included boilers and IGCC units that were construct ed for the purpose of selling one-third or less of their poten tial output or 219,000 MWh or less to the grid on an annual bas is. These units are not covered under subpart Da (the utility boiler and IGCC EGU criteria pollutant NSPS) but are ratherinstead covered as industrial boilers under subpart Db (industrial, institutional, and commercial boilers NSPS) or subp art KKKK (the combustion turbine criteria pollutant NSPS). We solicited comment on whether, to avoid implement ation issues related with different interpretations of “c onstructed for the purpose,” the electric sales criterion should be recast to be based on the permit conditions. Thetotal and percentage electric sales criteria should be recast to be base d on permit conditions. The “constructed for the purpose” langu age was included in the original subpart Da rulemaking. At that time, the vast majority of new steam generating units wer e clearly base load units. The “constructed for the purpose” language was intended to exempt industrial CHP units. These unit s tend to be relatively small and were not the focus of the rule making. In addition, units not meeting the electric sales appl icability criteria in subpart Da would be covered by other NS PS so there*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 194 of 854 is limited regulatory incentive, or impact to the e nvironment, for owners/operators to avoid applicability with th e utility NSPS. However, for new units, there is no correspon ding industrial unit CO 2 NSPS and existing units could debate their original intent (i.e., the purpose for which they w ere constructed) in an attempt to avoid applicability u nder section 111(d) requirements. Consequently, there could be a regulatory incentive for owners/operators to circumvent the CO 2 NSPS applicability. For units that avoid coverage, there would also be a corresponding environmental impact. For exampl e, an owner/operator of a new unit could initially reques t a permit restriction to limit electric sales to less than on e-third of potential annual electric output, but amend the ope rating permit shortly after operation has commenced to circumvent the intended applicability. Many existing units were initially b uilt with excess capacity to account for projected load growt h and were intended to sell more than one-third of their poten tial electric output. However, due to various factors (lower than expected load growth, availability of other lower cost units , etc.), certain units might have sold less than one-third o f their potential electric output, at least during their in itial period of operation. Therefore, the EPA has concluded that determining applicability based on whether a unit is “ constructed for the purpose of

supplying one-third or more of its potential elect ric*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 195 of 854 output and more than 219,000 MWh as net-electric sa les” (emphasis added) wouldcould create regulatory uncertainty and

could lead to applicability confusionuncertainty for both the regulated community and regulators. In addition, we have concluded that applicability based on actual operat ing conditions (i.e., actual electric sales) is not practical sinceideal because applicability would not be known prior to determining compliance and could change annually. Therefore, thisThis action finalizes applicability criteria based on design criteria characteristics and federally enforceable permit restrictions included in each in dividual permit. Based on permit restrictions, if any, of neton annual

total electric sales in the operating permit , it will be clear from the time of construction if awhether or not a new unit is subject to this rule. To be consistent with the applicability in subpart Da (i.e., ‘constructed for the purpose of’) , theThe applicability includes all utility boilers and IGCC units unless the electric sales restriction has always been included in the operating permit (i.e.,was in the original and remains in the current operating permit without any lapses ). (this is to be consistent with the ‘constructed for the purpose of ’ criteria in subpart Da). We have concluded that this approach is equivalent to, but clearer than, the existing language used in subpart Da. In addition, without the we have concluded that it is important*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 196 of 854 for both the 111(b) and 111(d) requirements for ele ctric-only steam generating units that the permit restriction to have always been subject to the limiting annual electric sales be included in both the original and current operating permit. Without this restriction, existing units could add permit restrictions on allowableavoid obligations under st ate plans developed as part of the 111(d) program by amending their operating permit to limit total annual electric sales to avoid obligation under 111(d).one-third of potential elec tric output. These units would not be subject to any GHG NSPS re quirements because they would not meet the 111(b) or 111(d) ap plicability criteria and, at this time, there is no NSPS that w ould cover these units. As described in Section III, industrial combined heat and powerCHP and dedicated non-fossil fuel units also are

not included in the scope ofaffected EGUs under this final action. In this rule, we are finalizing the definition of a steam generating EGU as a utility boiler or IGCC unit tha t: (1) is capable of combusting morehas a base load rating gr eater than 260 GJ/h ( 250 MMBtu/h heat input) of fossil fuel (either alone or in combination with any other fuel) and (2) serves a generator capable of supplying more than 25 MW - net to a utility distribution system (i.e., for sale to the grid). H owever, we are not establishing final GHGCO 2 standards for certain EGUs.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 197 of 854 These include: (1) steam generating units and IGCC facilitiesunits that are currently subject to - and have been continuously subject to - a federally enforceable permit limiting annual electric sales to one-third or less of their potential electric output (e.g., limiting hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less; (2) facilitiesunits subject to a federally enforceable permit that limits the use of fossil fuels to 10 percent or less of the unit’s heat input capa city on an annual basis; and (3) combined heat and power facilities technically capable of selling more electricity tha n the product of their design efficiency times their potential el ectric output, CHP units that are not subject to a federally enforceable permit condition limiting annual nettotal electric

sales to this amount (no more than their design efficiency times their potential electric output ), or to no more than 219,000 MWh (, whichever is greater ) or less

. 2. Applicability Specific to Newly Constructed Stea m Generating Units In CAA section 111(a)(2 )), a “new source” is defined as 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 per formance under this section which will be applicable to such source.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 198 of 854 Accordingly, for purposes of this rule, a newly con structed steam generating EGU is a unit that fits the defini tion and applicability criteria of a fossil fuel-fired steam generating EGU and commences construction on or after January 8, 2014, which is the date that the proposed standards were published for those sources (see 79 FR 1430). 3. Applicability Specific to Modified Steam Generat ing Units In CAA section 111(a)(4 )), a “modification” is defined as “any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results i n the emission of any air pollutant not previously emitte d.” The EPA, through regulations, has determined that certain ty pes of changes are exempt from consideration as a modifica tion. 187 For purposes of this rule, a modified steam generat ing EGU is a unit that fits the definition and applicabilit y criteria of a fossil fuel-fired steam generating EGU and that m odifies on or after June 18, 2014, which is the date that the pro posed standards were published for those sources (see 79 FR 34960).

187 40 CFR 60.2, 60.14(e )).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 199 of 854 4. Applicability Specific to Reconstructed Steam Ge nerating Units The NSPS general provisions (40 CFR part 60, subpar t A) provide that an existing source is considered a new source if it undertakes a “reconstruction,” which is the replace ment of components of an existing facility to an extent tha t : (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to co nstruct a comparable entirely new facility, and (2) it is tec hnologically and economically feasible to meet the applicable st andards. 188 For purposes of this rule, a reconstructed steam ge nerating EGU is a unit that fits the definition and applicab ility criteria of a fossil fuel-fired steam generating EG U and that reconstructs on or after June 18, 2014, which is th e date that the proposed standards were published for those sou rces (see 79 FR 34960). B. Best System of Emission Reduction 1. BSER for Newly Constructed Steam Generating Unit s TheIn the January 2014 proposal, the EPA proposed t hat highly efficient new generation technology implemen ting partial CCS is the BSER for GHG emissions from new steam ge nerating EGUs. (See generally 79 FR 1468-1469.) In this fina l action, the

188 40 CFR 60.15.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 200 of 854 EPA has determined that the BSER for newly construc ted steam generating units is partial implementation of carbon capture and storage (CCS)a new highly efficient supercritical p ulverized coal (SCPC) boiler implementing partial CCS technology to the extent of removal efficiency that meets a final emi ssion limitation of 1,400 lb CO 2 /MWh- grossg . The final standard of performance is less stringent than the proposed emi ssion limitation of 1,100 lb CO 2 /MWh- grossg . This change, as will be discussed in greater detail later in this preamble, is in response to public comments and reflects both a re-examination of the potential BSER technologies . For a and the most recent, reliable information regarding technology costs. A newly constructed fossil fuel-fired supercritical utility boiler , will be able to meet the final standard by implementing postcombustion carbon capture can be implemented by treating a slipstream of the combustion flue gas. For a newly constructed Alternative potential compliance paths are to build a new IGCC unit , a and co-fire with natural gas (or use pre-combustion

carbon capture system can be used to remove CO 2 from a partially shifted (or potentially un-shifted) syngas on a sli p- stream ),

or , alternatively for a supercritical utility boiler to co-fire with natural gas. The EPA of course realizes that the final standard of performance (1,400 lb CO 2 /MWh-g) differs from the proposed*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 201 of 854 standard (1,100 lb CO 2 /MWh-g). The EPA notes further, however, that the methodology for determining the final stan dard of performance is identical to that at proposal – dete rmining that a new highly efficient generating technology implem enting some degree of partial CCS is the BSER, with that degree of implementation being determined based on the reason ableness of costs. A key means of assessing the reasonableness of cost at proposal was comparison of the levelized cost of el ectricity (LCOE) with that of other dispatchable, base load n on-NGCC generating options. We have maintained that approac h in identifying BSER for the final standard. Applying t his methodology to the most recent cost information has led the EPA to adopt the final standard of performance of 1,400 lb CO 2 /MWh-g. See Section V.H at Table 8 below. This final standa rd reflects the level of emission reduction achievable by a hig hly efficient SCPC implementing the degree of partial CCS that re mains cost comparable to the other non-NGCC dispatchable base load generating options. The BSER for newly constructed steam generating EGU s in the final rule is very similar to that in the proposal. In this final action, the EPA finds that a highly efficient new SCPC EGU implementing partial CCS to the degree necessary to achieve an emission of 1,400 lb CO 2 /MWh-g is the BSER. Contrary to the January 2014 proposal, the EPA finds that IGCC tech nology –*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 202 of 854 either alone or implementing partial CCS – is not p art of the BSER, but rather is a viable alternative compliance option. As noted at proposal, a BSER typically advances perfor mance of a technology beyond current levels of performance. 79 FR 1465, 1471. Similarly, promotion of technology innovation can be a relevant factor in BSER determinations. Id. and Sec tion III.H.3.d above. For these reasons, the EPA at prop osal voiced concerns about adopting standards that would allow an IGCC to comply without utilizing CCS for slip-stream contro l. Id. at 1471. The final standard of 1,400 lb CO 2 /MWh-g, adopted as a means of assuring reasonableness of costs, allows I GCC units to comply without using partial CCS. Thus, although th e standard can be met by a highly efficient new IGCC unit usin g approximately 3 percent partial CCS (see Sections V .E and V.H.7 below), the EPA does not believe that implementatio n of partial CCS at such a low level, while technically feasible , is the option that utilities and project developers will c hoose. The EPA believes that IGCC project developers will eith er choose to meet the final standard by co-firing with natural gas - which would be a less costly and very straightforward pro cess for a new IGCC unit - or they will choose to install CCS equipment that will allow the facility to achieve much deeper CO 2 reductions than required by this rule – likely to c o-produce chemicals and/or to capture large volumes of CO 2 for use in EOR*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 203 of 854 operations. Similarly, project developers may also – as an alternative to utilizing partial CCS technology – m eet the final standard by co-firing approximately 40 percent natu ral gas in a new highly efficient SCPC EGU. While the EPA does not find that IGCC technology – either alone or with implementation of partial CCS - is pa rt of the BSER for new steam generating EGUs, we remain convi nced that it is technically feasible (see Section V.E below) and believe that it represents a viable alternative compliance optio n that some project developers will consider to meet the final standard issued in this action. The EPA notes further that I GCC is available at reasonable cost (see Table 9 below), a nd involves use of an advanced technology. So, although the fin al standard reflects performance of a BSER which includes parti al CCS, even in the instances that a compliance alternative migh t be utilized, that alternative would both result in emi ssion reductions consistent with use of the BSER, and wou ld reflect many of the underlying principles and attributes of the BSER (costs are both reasonable, not greatly dissimilar than BSER, no collateral adverse impacts on health or the environ ment, and reflects performance of an advanced technology). In reaching the final standard of performance, the EPA is aware that at proposal, the agency stated that it w as not “currently considering” a standard of performance a s high as*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 204 of 854 1,400 lb CO 2 /MWh-g. 79 FR 1471. However, in that same discussio n, the EPA noted the reasons for its reservations (chi efly reservations about the extent of emission reduction s, promotion

of advanced CO 2 control technologies, and whether the standard could be met by either utility boilers or IGCC unit s co-firing with natural gas, or otherwise complying without ut ilizing partial CCS), and we specifically solicited comment on the issue: “We request that commenters who suggest emis sion rates above 1,200 lb CO 2 /MWh address potential concerns about providing adequate reductions and technology development to b e considered BSER.” Id. The proposal thus both solicited comment on higher emission standards (including 1,400 lb CO 2 /MWh-g based on a less aggressive rate of partial CCS), and provided ample notice of the methodology the EPA would use to determine the final BSER and the corresponding final standard. 189 For these reasons, the EPA believes that it provided adequate notice of th is potential outcome at proposal, that the final standard of per formance was

189 Although co-firing with natural gas is not part of BSER, as noted above, it could be part of a compliance pathw ay for either SCPC or IGCC units. In this regard, a number of com menters addressed the issue of natural gas co-firing, indic ating that there were circumstances where it could be part of BSER. See e.g. Comments of Exelon Corp. p. 12; Comments of th e Sierra Club p. 108. See Northeast Md. Waste Disposal Authority v. EPA , 358 F.3d 936, 952 (D.C. Cir. 2004); Appalachian Power v. EPA , 135 F.3d 791, 816 (D.C. Cir. 1998) (commenters understo od a matter was under consideration when they addressed it in c omments).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 205 of 854 reasonably foreseeable, and that the final standard is a logical outgrowth of the proposed rule. Allina Health Services v. Sebelius , 746 F. 3d 1102, 1107 (D.C. Cir. . 2014). A more detailed discussion of the rationale for the final BSER determination and of other systems that were a lso considered is provided in Section V .P of this preamble. 190 2. BSER for Modified Steam Generating Units The EPA has determined that, as proposed, the BSER for steam generating units that trigger the modificatio n provisions is the modified unit’s own best potential performan ce. AsHowever, as explained below , however , the final BSER determination and the scope of modifications to whi ch the final

190 Certain commenters maintained that the BSER determ ination does not comply with (purportedly) binding legal re quirements created by regulations implementing the Information Quality Act. These comments are mistaken as a matter of both law and fact. The Information Quality Act does not create legal r ights in third parties (see, e.g. Mississippi Comm’n on Environmental Quality v. EPA , no. 12-1309 at 84 (D.C. Cir. June 2, 2015)), and the OMB Guidelines are not binding rules but rather , as their title indicates, guidance to assist agencies. See State of Mississippi , 744 F.3d at 1347 (the Guidelines provide “policy and procedural guidance”, are meant to be “flexible ” and are to be implemented differently by different agencies ac counting for circumstances). There are also significant factual omissions and mischaracterizations in these comments regarding pe er review of the proposed standard and underlying record informa tion. The complete response to these comments is in chapter 2 of the RTC. See also Section V.I.2.a and N below describing fin dings of the SAB panel that materials of the National Energy Tec hnology Laboratory had been fully and adequately peer revie wed, and that the EPA findings related to sequestration of captur ed CO 2 reflected the best available science.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 206 of 854 standards apply differ in some important respects from what the EPA proposed. The EPA proposed that the modified unit’s best potential performance would be determined depending upon when the unit implemented the modification (i.e., before or after being subject to an approved CAA section 111(d) state pla n). For units that commenced modification prior to becoming subje ct to an approved CAA section 111(d) state plan, the EPA pro posed unitspecific standards consistent with each modified un it’s best one-year historical performance (during the years f rom 2002 to the time of the modification) plus an additional tw o percent reduction. For sources that commenced modification after becoming subject to an approved CAA section 111(d) plan, the EPA proposed that the unit’s best potential performance would be determined from the results of an efficiency audit. The final standards in this action do not depend up on when the modification commences, as long as it commences after June 18, 2014. We are establishing emission standards fo r large modifications in this rule and deferring at this ti me the setting of standards for small modifications. In this final action, the EPA is issuing final emis sion

standards for large modifications to affected modified steam generating units that implement larger modifications that are consistent with the proposed BSER determination for modified*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 207 of 854 steam generatingthose units. The final standard for that subcategory of modifiedthose sources that implement larger modifications is a unit-specific emission limitation consistent with each modified unit’s best one-year historical performance (during the years from 2002 to the time of the modi fication ) –), but does not include the additional two percent red uction that was proposed in the January 2014 proposal. In this action, the EPA is not finalizing standards for

those sources that conduct smaller modifications resulting in a potential hourly increase in CO 2 emissions (mass per hour) of less than or equal to ten percent and is withdrawing the proposed standards for those sources . See Section XV below

. A more detailed discussion of the rationale for the BSER determination and final standards is provided in Se ction VI of this preamble. 3. BSER for Reconstructed Steam Generating Units Consistent with our proposal, the EPA has determine d that the BSER for reconstructed steam generating units i s the most efficient demonstrated generating technology for th ese types of units (i.e., meeting a standard of performance cons istent with a reconstructed boiler using the most efficient steam conditions available, even if the boiler was not originally de signed to do so). A more detailed discussion of the rationale fo r the BSER determination and the final standards is provided i n Section VII*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 208 of 854 of this preamble. C. Final Standards of Performance The EPA is issuing final standards of performance f or newly constructed, modified, and reconstructed affected s team generating units based on the degree of emission re duction achievable by application of the best system of emi ssion reduction for those categories, as described above. The final standards are presented below in Table 6. Table 6. Final Standards of Performance for New, Mo dified, and Reconstructed Steam Generating Units

Source SubcategoryDescription Final Standard* lb CO 2 /MWh- grg

New Sources AllAll newly constructed steam generating EGUs 1,400

Modified Sources Sources where the modification resultsthat implement larger modifications – those resulting in an increase in potential hourly CO 2 emissions (lb CO 2 /hr) of more than 10 percent Best annual performance (lb CO 2 /MWh- grossg ) during the time period from 2002 to the time of the modification

Reconstructed Sources Large** 1,800 Reconstructed Sources Small** 2,000 * Standards are to be met over a 12-operating-month compliance period. **Large units are those with heat input capacity of > 2,000 mmBtu/hr; Smallsmall units are those with heat input capacity of < ≤ 2,000 mmBtu/hr.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 209 of 854 For newly constructed and reconstructed steam gener ating units and for the subcategory of modified steam generating sources that result in more significantlarger hourly increases

of CO 2 emissions, the EPA is finalizing standards in the form of a gross energy output-based CO 2 emission limit expressed in units

of emissions mass per unit of useful energy output, specifically, in pounds of CO 2 per megawatt-hour (lb CO 2 /MWhgrg ). 191 The standard of performance wouldwill apply to affected

sourcesEGUs upon the effective date of the final action. The final method to calculate compliance is to sumCompliance with the final standard will be demon strated by summing the emissions (in pounds of CO 2 ) for all operating hours in the 12-operating-month compliance period and to dividethen dividing that value by the sum of the useful energy output (on a gross basis , i.e., gross megawatt-hours ) over the rolling 12- operating-month compliance period. The final rule requires rounding of emission rates with numerical values gr eater than or equal to 1,000 to three significant figures and rou nding of

191 Note that the standards for the subcategory of more significant modified sources that conduct larger modifications is a unit-specific numerical standard based on the unit’s best one-year historical performance during the period f rom 2002 to the time of the modification. The unit-specific sta ndard iswill also to be in the form of a gross energy output-based CO 2 emission limit expressed in units of emissions mass per unit of useful recovered energy, specifically, in pounds of CO 2 per megawatt-hour (lb CO 2 /MWh- grg ).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 210 of 854 rates with numerical values less than 1,000 to two significant figures. For newly constructed steam generating units, we pr oposed two options for the compliance period. We proposed that a newly constructed source could choose to comply with a 12 -operatingmonth standard or with a more stringent standard ov er an 84- operating-month compliance period , and we solicited comment on including an interim 12-operating-month standard (b ased on use of supercritical boiler technology, see 79 FR at 14 48). We are not finalizing the proposed 84-operating-month compliance period option that we proposed because the final standard of performance for newly constructed sourc es is less stringent than the proposed standard and because, a s discussed in Section V below, we are identifying alternative compliance pathways for both utility boilers and IGCC units.new steam generating EGUs. Specifically, we have concluded that there are unlikely to be significant issues with short-term v ariability during initial operation, in view of both the reduc ed numerical stringency of the standard, and the availability of compliance alternatives. The EPA notes that co-firing of natur al gas can also serve as an interim technologymeans to reduce emissions if a new source operator believes additional time is n eeded to phase-in the operation of a CCS system. Therefore, the applicable final standards of performance for all n ewly*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 211 of 854 constructed, modified, and reconstructed steam gene rating units must be met over a rolling 12-operating-month compl iance period. In the Clean Power Plan, which is a separate rulema king under CAA section 111(d) published at the same time as the present rulemaking under CAA section 111(b), the EP A is promulgating emission guidelines for states to deve lop state plans regulating CO 2 emissions from existing fossil fuel-fired EGUs. Existing sources that are subject to state pl ans under CAA section 111(d) may undertake modifications or recon structions and thereby become subject to the requirements unde r section 111(b) in the present rulemaking. In the section 11 1(d) Clean Power Plan rulemaking, the EPA discusses how undert aking a modification or reconstruction affects an existing source’s section 111(d) requirements. V. Rationale for Final Standards for Newly Construc ted Fossil Fuel-fired Electric Utility Steam Generating Units In the discussion below, the EPA describes the rati onale and justification of the BSER determination and the resulting final standards of performance for newly constructe d steam generating units. We also explain why this determin ation is consistent with the constraints imposed by the EPAc t05. A. Factors Considered in Determining the BSER In evaluating the final determination of the BSER f or newly constructed steam generating units, the EPA conside red the*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 212 of 854 factors for the BSER described above, looked widely at all relevant information and considered all the data, i nformation, and comments that were submitted during the public comment period. We re-examined and updated the information that was available to us and concluded, as described below, that the final standard of 1,400 lb CO 2 /MWh- gross, issued in this action and reflecting certain key changes from the proposa l,g is consistent with the degree of emission reduction ac hievable through the implementation of the BSER. This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable pa th forward for the construction of new coal-fired generating s ources that

addresses greenhouse gasGHG emissions and supports technological innovation

. B.B. Highly Efficient SCPC EGU Implementing Partial CCS as the BSER for Newly Constructed Steam Generating Units In the January 2014 proposal, we proposed that part ial CCS technology with a percentage capture that would res ult in an emission limitation of 1,100 lb CO 2 /MWh-gross is the BSER for new fossil fuel-fired steam generating units, that is, for both utility boilers and IGCC units. For a new utility b oiler firing bituminous coal, the BSER at proposal would be capt ure and storage (that is, either storage on-site or transfe r to a qualified storage facility) of approximately 40 per cent of the*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 213 of 854

CO 2 from the source. In this final action, we affirm t hat partial CCS technology represents the best system of emissi on reduction for new steam generating units, but we have determi ned that the percentage of capture that qualifies as the BSER sh ould be reduced to the amount that would result in an emiss ion limitation of 1,400 lb CO 2 /MWh-gross. For a new utility boiler firing bituminous coal, the BSER would be capture a nd storage of approximately 20 percent of the CO2 from the source . The change from the proposed emission limitation to the final emission limitation reflects response to comments received o n the proposed standards and is largely based on our asse ssment of comments received on the estimated costs to impleme nt partial

CCS. In the sections that follow, we explain the technic al configurations that may be used to implement partial captureBSER to meet the final standard, describe the operationa l flexibilities that partial captureCCS offers, and then provide

the rationale for the final standard of performance. Af ter that, we discuss, in greater detail, consideration of the criteria for the determination of the BSER. We describe why a highly efficient new SCPC EGU implementing partial capture and storageCCS in the amount that results in an emission limitati on of 1,400 lb CO 2 /MWh- grossg best meets those criteria, including, among others, that partial capture and storagesuch a system is technically feasible, provides meaningful emission reductions,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 214 of 854 can be implemented at a reasonable cost, anddoes not pose nonair quality health and environmental concerns or im pair energy reliability, and consequently is adequately demonstrated. We also explain why the emission standard of 1,400 lb CO 2 /MWh-g is achievable, including under all circumstances reaso nably likely to occur when the system is properly designed and o perated. We also discuss alternative (i.e., non-CCS) compliance options that new source project developers can also useelect to use, instead of SCPC with partial CCS, to meet the final standard of performance. We also explain why the emission standard of 1,400

lb CO 2 /MWh-gross is achievable. C. Rationale for the Final Emission Standards 1. The Proposed Standards In the January 2014 proposal, the EPA proposed an e mission limitation of 1,100 lb CO 2 /MWh- grg , which would have required a

new steam generating unithighly efficient utility boile r burning bituminous coal to capture and store (including either storage on-site or transfer to a qualified storage facility )could have met by capturing roughly 40 percent of its CO 2 emissions and a

new highly efficient IGCC unit to capturecould have met by capturing and storestoring roughly 25 percent of its CO 2 emissions. The captured CO 2 would then be securely stored in sequestration repositories subject to either Class II or Class VI standards under the Underground Injection Contro l program.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 215 of 854 The EPA arrived at thosethe proposed levelsstandard by examining the available CCS implementation configurations and concluding

that this level the proposed standard at the correspondi ng levels of partial CCS best balancesbalanced the BSER criteria

and resultsresulted in an achievable emission level. The EPA did not proposealso proposed to find that highly efficient new generation implementing “full CCS” (i.e., more than 90 percent capture and storage) to bewas not the BSER because the expected

costs to implement the technology are highof that configu ration – for both utility boilers and IGCC units - are projected to substantially exceed the projected costs of other non-NGCC dispatchable technologies that utilities and project developers are considering (e.g., new nuclear and biomass). Se e generally 79 FR at 1477-78. Conversely, the EPA rejected highly efficient SCPC as the BSER because it would not result in mea ningful emission reductions from any newly constructed PC u nit. Id. at 1470. The EPA also declined to base the BSER on IGC C operating alone due to the same concern – lack of emission re ductions from a new IGCC unit otherwise planned. Id. 2. Basis for the Final Standards For this final action, the EPA reexamined the technologyBSER options available at proposal. Those options are: (1) highly efficient generation without CCS, (2) highly efficient generation implementing partial CCS, and (3) highly*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 216 of 854 efficient generation implementing full (i.e., more than 90 percent) CCS. Consistent with our determination in the Janua ry 2014 proposal, we remain convinced that highly effi cient generation (i.e., a new supercritical utility boiler or a new IGCC unit) without CCS does not represent the best systemBSER because it does not achieve emission reductions bey ond the sector’s business as usual, when options that do ac hieve more emission reductions are available. 79 FR 1470; see also Section

V.P below. We also do not find that a highly efficient new steam generating unit implementing full CCS is the BSER because, at this time, the costs are predicted to be significan tly more than

thatthe costs for implementation of partial CCS and significantly more than completingthe costs for competing nonNGCC base load, dispatchable technologies such as- primarily new

nuclear -powered generation - and are, therefore, potentially unreasonable. See Section V.P

. As with the proposal, the EPA has determined the fi nal BSER and corresponding emission limitation by appropriat ely balancing the BSER criteria and determining that the emission limitation is achievable. The percentage capture and final standard of performance of 1,400 lb CO 2 /MWh- gross areg is less stringent than at proposal and reflectreflects changes that wereare responsive to comments received on, and the EPA’s further eval uation of, the costs to implement partial CCS. The EPA has det ermined that*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 217 of 854 a newly constructed highly efficient supercritical utility boiler burning bituminous coal can meet this final emission limitation by capturing and storing (including on-site storage or transfer to a qualified facility) approximately 2016 percent of the CO 2 produced from the facility . Most new IGCC units will be able to meet the emission limitation using more limited CCS (i.e., less than 10 (or 23 percent ). if burning subbituminous or dried lignite), which would be either stored in on- site or offsite geologic sequestration repositories subject to control under either the Class VI (for geologic sequestrati on) or Class II (for Enhanced Oil Recovery) standards under the UIC program. This BSER is technically feasible, as shown by the fact that post-combustion CCS technology – both the capture and storage components - is demonstrated in full-scale operation within the electricity generating industry , and full-scale pre-combustion CCS has been demonstrated in several chemical indus try plants with results that are reasonably transferable to th e electricity generating sector.. There are also numerous operating results

from smaller-scale operationsprojects that are reasonably predictive of operation at full-scale. In addition, partial CCS will result in substantial emissions reductionsIt i s available at reasonable cost, is consistent with the other BSER criteria, is adequately demonstrated, and is consistent with emission standards that are achievabledoes not only through partial CCS*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 218 of 854 but also through alternative compliance approachesh ave collateral adverse non-air quality health or enviro nmental impacts, and does not have adverse energy implicati ons . The proposed BSER was a highly efficient newly cons tructed steam generating EGU implementing partial CCS to an emission standard of 1,100 lb CO 2 /MWh-g. The final BSER is a highly efficient SCPC EGU implementing partial CCS to achi eve an emission standard of 1,400 lb CO 2 /MWh-g. In both cases, the EPA specified that the BSER includes a “highly efficien t” new EGU implementing partial CCS. This assumes that a new p roject developer will construct the most efficient generat ing technology available – i.e., a supercritical or ult rasupercritical utility boiler – that will inherently generate lower volumes of uncontrolled CO 2 per MWh. See Section V.J below. A well performing and highly efficient new SCPC EGU will need to implement lower levels of partial CCS in order to m eet the final standard of 1,400 lb CO 2 /MWh-g than a less efficient new steam generating EGU. The construction of highly efficien t steam generating EGUs – as opposed to less efficient unit s such as a subcritical utility boiler – will result in lower o verall costs from decreased fuel consumption and the need for lo wer levels of required partial CCS to meet the final standard.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 219 of 854

3. Consideration of Projects Receiving Funding Under t he EPAct05 As noted in Section III. KH.3.g above, the EPA’s determination of the BSER here includes review of recently constructed facilities and those planned or under c onstruction , to evaluate the control technologies being used and considered. Some of the projects discussed in the January 2014 proposal, and discussed here in this preamble, received or are re ceiving financial assistance under the EPAct05 (P.L. 109-58 ). This assistance may include financial assistance from the Department of Energy (DOE), as well as receipt of the Federalfederal tax credit for investment in clean coal technology unde r IRC sectionSection 48A. As noted above, the EPA interprets these provisions as allowing consideration of EPAct05 facilities provid ed that such information is not the sole basis for the BSER dete rmination, and particularly so in circumstances like those her e, where the information is corroborative but the essential info rmation justifying the determinations comes from facilities and other sources of information with no nexus with EPAct05 a ssistance. In the discussion below, the EPA explains its relia nce on other information in making the BSER determination for ne w fossil fuel-fired steam generating units. The EPA notes th at information from facilities that did not receive an y DOE assistance standing alone, and did not receive the federal ta x*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 220 of 854 credit, is sufficient by itself to support its BSER determination. D. Post-Combustion CCSCarbon Capture

In this section on post-combustion CCS , we describe a variety of facts that support our conclusion that t he technical feasibility of post-combustion carbon capture is adequately demonstrated. First, we describe the technology of postcombustion capture , citing authoritative sources.. We then describe EGUs that have previously utilized or demonstrated, or are currently utilizing , post-combustion carbon capture technology. Further,This discussion is complemented by later sections that explain and justify our conclusions t hat the technical feasibility of other aspects of partial C CS are adequately demonstrated – namely, the transportatio n and carbon storage (see Sections V.M. and N). Further, the con clusions of this section are reinforced by the discussion in Se ction V.F. below, in which we identify commercial vendors that offer carbon capture technology and offer performance guarantees . In addition, we note that , and discuss industry and technology developers have publically stateddevelopers’ public pronouncements of their confidence in the feasibility and availability of CCS technologies.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 221 of 854

1. Post-combustion Carbon Capture – How it Works Post-combustion capture processes remove CO 2 from the exhaust gas of a combustion system – such as a util ity boiler. It is referred to as “post-combustion capture” beca use the CO 2 is the product of the combustion of the primary fuel a nd the capture takes place after the combustion of that fu el. The exhaust gases from manymost combustion processes are often at atmospheric pressure and are moved through the flue gas system by fans , and the. The concentration of CO 2 in most combustion flue gas streams is somewhat dilute. 192 Most post-combustion capture systemsystems utilize liquid solvents 193 that separate

the CO 2 from the flue gas in CO 2 scrubber systems . Because the flue gas is at atmospheric pressure and is somewhat dilute, the solvents used for post-combustion capture are ones that separate

the CO 2 using chemical absorption (or chemisorption). Amin e-based

solvents 194 are the most commonly used in post-combustion capt ure systems. In a chemisorption-based separation proces s, the flue gas is processed through the CO 2 scrubber and the CO 2 is absorbed by the liquid solvent and then released by heating to form a

192 The typical concentration of CO 2 in the flue gas of a coalfired utility boiler is roughly around 15 volume pe rcent. 193 A solvent is a substance (usually a liquid) that dissolves a solute (a chemically different liquid, solid or gas), res ulting in a solution. 194 Amines are derivatives of ammonia (NH 3 ) where one or more hydrogen atoms have been replaced by hydrocarbon gr oups.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 222 of 854 high purity CO 2 stream. This heating step is referred to as “solvent regeneration” and is responsible for much of the “energy penalty” of the capture system. Steam from the boiler (or potentially from another external source) that would otherwise be used to generate electricity is instea d used in the solvent regeneration process. DevelopmentThe development of advanced solvents – those that are chemically stabl e, have high

CO 2 absorption capacities, and have low regeneration e nergy requirements – areis an active area of research. Many postcombustion solvents will also selectively remove ot her acidic gases such as sulfur dioxide ( SO 2 ) and hydrochloric acid (HCl), which can result in degradation of the solvent. In thoseFor that reason, the CO 2 scrubber systems are normally installed downstream of other pollutant control devices (e.g. , particulate matter and flue gas desulfurization controls) and i n some cases, the acidic gases will need to be scrubbed to very l ow levels prior to the flue gas entering the CO 2 capture system. See also RIA chapter 5 (quantifying SO 2 reductions resulting from this scrubbing process).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 223 of 854 Additional information on post-combustion carbon ca pture – including process diagrams - can be found in a summary technical support document. 195 2. Post-combustion Carbon Capture Projects That Havethat have not Received DOE Assistance Throughthrough the EPAct05 or Tax Credits Underunder IRC sectionSection 48A

a. Boundary Dam Unit #3

. SaskPower’s Boundary Dam CCS Project in Estevan, a city in Saskatchewan, Canada, is the world’s first commerci al-scale fully integrated post-combustion CCS project at a c oal-fired power plant. The project fully integrates the rebui lt 110 MW coal-fired Unit #3 with a CO 2 capture system using Shell Cansolv amine-based solvent to capture 90 percent of its CO 2 emissions. The facility, which utilizes local Saskatchewan lig nite, began operations in October 2014 and accounts of the syst em’s performance describe it as working even “better than

195 Technical Support Document – “Literature Survey of Carbon Capture Technology”, available in the rulemaking do cket (Docket ID: EPA-HQ-OAR-2013-0495).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 224 of 854 expected.” 196,197 The plant started by capturing roughly 75 percent

of CO 2 from the plant emissions and its operators plan to increase the capture percentage as they optimize th e equipment to reach full capacity. Initial indications are tha t the generation sidefacility is producing more power than estimatedpredicted and that the energy penalty (parasitic load – the energy needed to regenerate the CO 2 capture solvent ) is much

lower than expectedinitially predicted

. 198 Water use at the facility is consistent with levels that were predic ted. 199 The total project costs – for the power plant and the c arbon capture plant – was $1.467B (CAD). 200 The CO 2 from the capture system is more than 99.999 percent pure with only trace level s of N 2 in the

196 “[W]e are achieving better than expected” operatio n out of the plant, SaskPower's Mike Marsh said April 8 , 2015 in Washington, DC, summarizing the status of the first -of-a-kind plant in Saskatchewan, Canada, known as Boundary Da m Unit 3. Marsh spoke at a meeting of the National Coal Counc il, which advises the Energy Department on coal-related topic s. From “Bolstering EPA’s NSPS, Canadian CCS Plant Working ‘Better Than Expected’”, Climate Daily News, Inside EPA/climate (April 08, 2015); www.insideepa.com (subscription required). 197 “CCS performance data exceeding expectations at wo rld-first Boundary Dam Power Station Unit #3”, http://www.saskpowerccs.com/newsandmedia/latest-new s/ccsperformance-data-exceeding-expectations //. 198 Correspondence between Mike Monea (SaskPower) and Nick Hutson (EPA), February 20, 2015. 199 30 percent of the water used for cooling comes fro m the recycled or reclaimed water from the process itself ; namely , water in the coal is reclaimed. 200 About $1.2B USD; roughly $700M (USD) for the carbo n capture system, which was on budget.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 225 of 854 product stream. 201 This purity is food-grade quality CO 2 and is a clear indication that the system is working well. T he captured

CO 2 is transported by pipeline to nearby oil fields in southern Saskatchewan where it will beis being used for enhanced oil recovery ( EOR ) operations. Any captured CO 2 that is not used for EOR operations will be stored in nearby deep brine- filled sandstone formations. Thus , the Boundary Dam Unit #3 project is demonstrating CO 2 post-combustion capture, CO 2 compression and transport, and CO 2 injection for both EOR and geologic storage. The CCS system is fully integrated with the electri city production of the plant. Some commenters noted that, at 110 MW, the Boundary Dam Unit #3 is a relatively small coal-fired utility bo iler and

thus , in the commenters’ view, does not indicatedemonstrate that such a system could be utilized at a much larger ut ility coalfired boiler. However, there is nothing to indicate that the post-combustion system used at Boundary Dam could n ot be scaledup for use at a larger utility boiler. In fact, the carbon capture system at Boundary Dam #3 is designed and c onstructed to implement “full CCS” – that is to capture more than 90 percent

of the CO 2 produced from the subcritical unit. A similarly-si zed

201 “Boundary Dam – The Future is Here”, plenary prese ntation by Mike Monea at the 12 th International Conference on Greenhouse Gas Technologies (GHGT-12), Austin, TX (October 2014).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 226 of 854 capture system – with no need for further scale-up - could be

used to treat a slipstreamslip-stream of a much larger supercritical utility boiler ( a new unit of approximately 500 to 600 MW) in order to meet the final standard of perf ormance of 1,400 lb CO 2 /MWh- grossg , which would only require partial CCS on the order of approximately 2016 to 23 percent . (depending on the coal used). A “ slipstreamslip-stream ” is a portion of the flue gas stream that can be treated separately from the bulk exhaust gas. It is not an uncommon configuration for the flue ga s from a coal-fired boiler to be separated into two separateor more streams and treated separately in different control equipment before being recombined to exit from a common stack

. 202 A slipstreamslip-stream configuration is often used to treat a smaller portion of the bulk flue gas stream as a wa y of testing or demonstrating a control technologydevice or measurement technology. For implementation of partial post-combustion partial carbon capture, a portion of the bulk flue gas str eam would be treated separately to capture approximatel y 90 percent

of the CO 2 from that smaller portionslip-stream of the flue gas. For example, in order to capture 20 percent of the CO 2 produced by a coal-fired utility boiler, an operator would t reat

202 See Figure 1A from Atmospheric Environment , 43, 3974 (2009), for an example of this type of configuration.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 227 of 854 approximately 25 percent of the bulk flue gas strea m (rather than treating the entire stream). Approximately 90 percent of

the CO 2 would be captured from the slipstreamslip-stream gas –, resulting in an overall capture of about 20 percent

. In its study on the cost and performance of a range of carbon capture rates , the DOE/NETL determined that the slipstreamslip-stream approach was the most economical for carbon capture of less than 90 percent of the total CO 2 . 203 The advantagesadvantage of the slipstreamslip-stream approach is that the capture system will be sized to treat a lo wer volume of flue gas flow, which reduces the size of the CO 2 absorption columns, induced draft fans, and other equipment, l eading to lower capital and operating costs. The carbon capture system at Boundary Dam does not utilize

the slipstreamslip-stream configuration because it was designed to achieve more than 90 percent capture rates from the 110 MW facility. However, the same carbon capture equipmen t could be used to treat approximately 50 percent of the flue gas from a

203 “Cost and Performance of PC and IGCC for a Range o f Carbon Capture”, Rev 1 (2013), DOE/NETL-2011/1498 . Page p. 2 : “ (“ A literature search was conducted to verify that <90 percent CO 2 capture is most economical using a “slip-stream”’slip-stream’ (or bypass) approach. Indeed, the slip-stream appro ach is more cost-effective for <90 percent CO 2 capture than removing reduced CO 2 fractions from the entire flue gas stream, accordi ng to multiple peer-reviewed studies.” See also id. at 19 , 21, 77, and 478 (documenting further that treating a slip-strea m is the most economical approach).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 228 of 854 220 MW facility – or 20 percent of the flue gas from a 550 MW facility. Thus , the equipment that is currently working very well (in fact, “better than expected”) at the Bound ary Dam plant can be utilized for partial carbon capture at a muc h larger coal-fired unit – without the need for further scale-up. The experience at Boundary Dam is directly transfer rable to other types of post-combustion sources, including t hose using different boiler types and those burning different coal types. There is nothing to suggest that the Shell CanSolv process would not work with other coal types . The EPA is not aware and indeed, the latest NETL cost estimates assume that the capt ure technology would be used in a new unit using bitumi nous coal. 204

The EPA is unaware of any reasons why the Boundary Dam technology would not be transferrable to another ut ility boiler at a different location at a different elevation or climate

. 205 because the control technology is not climate or el evationdependent.

204 In fact, in “Cost and Performance Baseline for Fos sil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3”, DOE/NETL-2015/1723 (July 2 015), Exh.2-3 the Shell Cansolv process is used as the capture pr ocess for a new SCPC unit using bituminous coal rather than the subcritical PC unit at Boundary Dam that uses Canadian lignite. The study evidently assumes that the CanSolv process can be u sed effectively for bituminous coal since this type of coal is assumed for cost estimation purposes. 205 In fact, Saskatchewan’s harsh winter weather and r elative remote location are two of the reasons given for Bo undary Dam’s relatively high costs.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 229 of 854 Commenters also noted that the Boundary Dam Unit #3 project received financial assistance from both the Canadia n federal government and from the Saskatchewan provincial gov ernment. But the availability of – or the lack of – external fin ancial assistance does not affect the technical feasibilit y of the technology. Commenters further characterized Bounda ry Dam as a “demonstration project”. These descriptors are besi de the point. Regardless of what the project is called or how it was financed, the project clearly shows the technical feasibility of fullscale, fully integrated implementation of available postcombustion CCS technology, which in this case also appears to be commercially viable. The EPA notes that, although there is ample additio nal information corroborating that post-combustion CCS is technically feasible, which we describe below, the performance at Boundary Dam Unit #3 alone would be sufficient t o support that conclusion. Essex Chemical Corp., 486 F. 2d at 436 (test results from single facility demonstrates achievabi lity of standard of performance). As mentioned above, the postcombustion capture technology used at Boundary Dam is transferrable to all other types of utility boilers

. b. AES Warrior Run and Shady Point

. AES’s coal-fired Warrior Run (Cumberland, MD) and S hady Point (Panama, OK) plants are both circulating fluidized bed*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 230 of 854 (CFB) coal-fired power plants with carbon capture equipment that is equipped with amine scrubbers developed by ABB/Lummus. The scrubbers were designed to process a slipstreamslip-stream of each plant’s flue gas. At the 180 MW Warrior Run plantPlant , a plant that burns bituminous coal, approximately 10 percent of the plant’s CO 2 emissions (about 110,000 metric tons of CO 2 per year) has been captured since 2000 and sold to the food and beverage industry. At the 320 MW Shady Point Plant, a plant that burns a blend of bituminous and subbituminous coals , CO 2 from an approximate 5 percent slipstreamslip-stream (about 66,000 metric

tons of CO 2 per year) has been captured since 2001. The captur ed

CO 2 from the Shady Point Plant is also sold for use in the food processing industry. 206 While these projects do not demonstrate

the CO 2 storage component of CCS, they clearly demonstrate the technical viability of partial CO 2 capture. The capture of CO 2 from a slip-stream of the bulk flue gas, as describ ed earlier, is the most economical method for capturing less th an 90 percent

of the CO 2 . The amounts of partial capture that these sources have demonstrated – up to 10 percent – is reasonabl y similar to the level, at 16 to 23 percent, that the EPA predic ts would be needed by a new highly efficient steam utility boil er to meet

206 Dooley, J. J., et al. (2009). “ An Assessment of the Commercial Availability of Carbon Dioxide Capture a nd Storage Technologies as of June 2009 .”. U.S. DOE, Pacific Northwest National Laboratory, under Contract DE-AC05-76RL018 30.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 231 of 854 the final standard of performance. These facilities , which have been operating for multiple years, clearly show the technical feasibility of post-combustion carbon capture.

c. Searles Valley Minerals

. Since 1978, the Searles Valley Minerals soda ash pl ant in Trona, CA , has used post-combustion amine scrubbing to captur e approximately 270,000 metric tons of CO 2 per year from the flue gas of a coal-fired power plant that generates stea m and power for on-site use. The captured CO 2 is used for the carbonation of brine in the process of producing soda ash. 207 Again, while the captured CO 2 is not sequestered, this project clearly demonstrates the technical feasibility of the amine scrubbing system for CO 2 capture from a coal-fired power plant. 208 The fact that this system is an industrial coal-fired power plant rather than a utility coal-fired power plant is irrelevant as they both serve a similar purpose – the production of electri city. Each of these processes indicate a willingness of i ndustry to utilize available post-combustion technology for capture of

CO 2 for commercial purposes. Not one of the CO 2 capture systems at Warrior Run, Shady Point, or Searles Valley was installed for regulatory purposes or as government-funded demonst ration

207 IEA (2009), World Energy Outlook 2009, OECD/IEA, P aris. 208 Moreover, the final rule allows alternative means of storage of captured CO 2 based on a case-by-case demonstration of efficacy. See Section V.M.4 below.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 232 of 854 projects. They were installed to capture CO 2 for commercial use. The fact that the captured CO 2 was utilized rather than being stored is of no consequence in the consideration of the technical feasibility of post-combustion CO 2 capture technology. These commercial operations have helped to improve the performance of scrubbing systems that are available today. For example , the heat duty (i.e., the energy needed to remove t he

CO 2 ) has been reduced by about 5 times from the amine process originally used at the TronaSearles Valley facility as compared to the solvents that are being. The amine scrubbing process used at Boundary Dam is equally efficient, and the amine scrubbing system to be used at the Petra Nova WA Parish project (Thompsons, TX ).) is projected to be as well. 209

3. Post-combustion Carbon Capture Projects that Received DOE Assistance Throughthrough the EPAct05 , but did not Receive Tax Credits Underunder IRC sectionSection 48A The EPA considers the experiences from the CCS proj ects described above, coupled with factsevidence that the design of CCS is well accepted (also described above) and the strong

209 The heat duty for the amine scrubbing process used at Searles Valley in the mid-70’s was about 12 MJ/mt CO 2 removed as compared to a heat duty of about 2.5 MJ/mt CO 2 removed for the amine processes used at Boundary Dam and to be used at WA Parish. “From Lubbock, TX to Thompsons, TX - Amine Scrubbin g for Commercial CO 2 Capture from Power Plants”, plenary address by Prof. Gary Rochelle at the 12 th International Conference on Greenhouse Gas Technology (GHGT-12), Austin, TX (Oc tober 2014).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 233 of 854 support that CCS has received from vendors and othe rs (described below) to adequately demonstrate that post-combustion partial CCS is technically feasible. The EPA finds that add itional projects, described next, provide more support for that conclusion. These projects received funding under E PAct05 from the Department of Energy, but for the reasons discussed below, that does not disqualify them from being considered . See Section III.H.3 above

. a. Petra Nova WA Parish Project. project Petra Nova, a joint venture between NRG Energy Inc. and JX Nippon Oil & Gas Exploration, is constructing a com mercial-scale post-combustion carbon capture project at Unit #8 of NRG's WA Parish generating station southwest of Houston, Tex as. The project is designed to utilize partial CCS by captu ring approximately 90 percent of the CO 2 from a 240 MW slipstreamslipstream of the 610 MW WA Parish facility. ThisThe project is an indication that developers are confidentexpected to be operational in 2016 and thus does not yet directly demonstrate the technical feasibility ofor performance of the MHI amine scrubbing system. However, this project is a clear indication that the developers have confidence in the technica l feasibility

of the post-combustion carbon capture system . The project was originally envisioned as a 60 MW slipstreamslip-stream demonstration and received DOE Clean Coal*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 234 of 854 Power Initiative ( CCPI ) funding (as provided in EPAct05) on that basis. The project wasdevelopers later expanded the project to the larger 240 MW slipstreamslip-stream because of the need to capture largergreater volumes of CO 2 for EOR operations. No additional DOE or other federal funding was obtaine d for the expansion from a 60 MW slipstreamslip-stream to a 240 MW slipstreamslip-stream

. 210 At 240 MW, the Petra Nova project will be the large st postcombustion carbon capture system installed on an ex isting coalfueled power plant. The project will use for EOR or will sequester 1.6 million tons of captured CO 2 each year. The project is expected to be operational in 2016. In 2014 project materials 211 ,, 212 the project developer NRG recognized the importance of CCS technology by noti ng:

“ The technology has the potential to enhance the lon gterm viability and sustainability of coal-fueled po wer plants across the U.S. and around the world .” ... “

. ... Post-combustion carbon capture is essential so that we

210 Thus, even if the fact that the project received DOE assistance for the initial , 60 MW design, the expansion of the project from 60 MW to 240 MW should not be consider ed a DOEassisted project. AsIn any case, as described above, even without consideration of this facility at all, othe r information adequately demonstrates the technical feasibility o f postcombustion CCS. 211 WA Parish CO 2 Capture Project Fact Sheet; available at www.nrg.com/documents/business/pla-2014-petranova-w aparishfactsheet.pdf (2014) 212 WA Parish CO 2 Capture Project Fact Sheet; available at www.nrg.com/documents/business/pla-2014-petranova-w aparishfactsheet.pdf (2014).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 235 of 854 can use coal to sustain our energy ecosystem while we begin reducing our carbon footprint .”

.

According to NRG, the Petra Nova Carbon Capture Pro ject will utilize “a proven carbon capture process ”,,” jointly developed by Mitsubishi Heavy Industries, Ltd. (MHI ) and the Kansai Electric Power Co., that uses a high-perform ance solvent

for CO 2 absorption and desorption. 213 In using the MHI highperformance solvent, the Petra Nova project will be nefit from pilot-scale testing of this solvent at Alabama Powe r’s Plant Barry and at other installations. AsWA Parish Unit #8 came online in 1982 and is thus an existing source , the WA Parish facility that will not be subject to final standards of performance issued in this action. However, sincebecause it will be capturing roughly 35 percent of the CO 2 producedgenerated by the facility, it should meetits emissions will be below the final new source emission limitation of 1,400 lb CO 2 /MWhgross.g. 214

213 The WA Parish project (described earlier) will uti lize the KM-CDR Process®, which was jointly developed by MHI and the Kansai Electric Power Co., Inc. and uses the propri etary KS-1TM high-performance solvent for the CO 2 absorption and desorption.

214 Using emissions data reported to the Acid Rain Pro gram, the EPA estimates that the CO 2 emissions from the WA Parish Unit #8 will be 1,250 – 1,300 lb CO 2 /MWh-g during operations with the post-combustion capture system.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 236 of 854 The captured CO 2 from the WA Parish CO 2 Capture Project will be used in EOR operations at mature oil fields in t he Gulf Coast region. Using EOR at Hilcorp's West Ranch Oil Field , the production is expected to be boosted from around 50 0 barrels per day to approximately 15,000 barrels per day. Thus t he project will utilize all aspects of CCS by capturing CO 2 at the large coal-fired power plant, compressing the CO 2 , transporting it by pipeline to the EOR operations, and injecting it fo r EOR and eventual geologic storage. The carbon capture system at WA Parish will utilize a slipstreamslip-stream configuration. However, as noted, the system is designed to capture roughly 35 percent of the CO 2 from

the WA Parish Unit #8 (90 percent of the CO 2 from the 240 MW slipstreamslip-stream from the 610 MW unit). A carbon capture system of the same size as that used at WA Parish c ould be used to treat a 240 MW slipstreamslip-stream from a 1,000 MW unit in order to meet the final standard of performance of 1,400 lb

CO 2 /MWh- grossg . Again, the experience at the WA Parish Unit #8 project will be directly transferable to post-combustion capture at a new utility boiler, even though WA Parish is an existing source.Unit #8 is an existing source that has been in operation for over 30 years. In fact, retrofit of such technology at an e xisting unit can be more challenging than incorporating the tech nology into*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 237 of 854 the design of a new facility. The experience will be directly transferrable to other types of post-combustion sou rces including those using different boiler types and th ose burning different coals. The amine scrubbing and associated systems are not boiler type- or coal-specific. The EPA is unaware of any reasons that the technology utilized at the WA Pari sh plant would not be transferrable to another utility boile r at a different location at a different elevation or clim ate , given that the technology is not dependent on either clim ate or topography

. b. AEP/Alstom Mountaineer Project. project In September 2009, AEP began a pilot-scale CCS demonstration at its Mountaineer Plant in New Haven , WV. The Mountaineer Plant is a very large (1,300 MW) coal-f ired unit that was retrofitted with Alstom’s patented chilled ammonia CO 2 capture technology on a 20 MWe slipstreamslip-stream of the plant’s exhaust flue gas. In May 2011, Alstom Power announced the successful operation of the chilled ammonia CCS validation project. The demonstration achieved capture rates f rom 75 percent (design value) to as high as 90 percent, an d produced CO 2 at a purity of greater than 99 percent, with energy penalties within a few percent of predictions. The facility r eported robust steady-state operation during all modes of p ower plant*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 238 of 854 operation , including load changes, and saw an availability of the CCS system of greater than 90 percent. 215 AEP, with assistance from the DOE, had planned to e xpand

the slipstreamslip-stream demonstration to a commercial scale, fully integrated demonstration at the Mountaineer f acility. The commercial-scale system was designed to capture at least 90 percent of the CO 2 from 235 MW of the plant's 1,300 MW total capacity. Plans were for the project to be complete d in four phases, with the system to begin commercial operati on in 2015. However, in July 2011, AEP announced that it would terminate its cooperative agreement with the DOE and place its pl ans to advance CO 2 capture and storage technology to commercial scale on hold. AEP cited the uncertain status of U.S. climat e policy as a contributor to its decision, andbut did not express doubts about the feasibility of the technology. See Section V.L below. AEP also prepared a Front End Engineering & Design (FEED) Report , 216 , explaining in detail how its pilot-scale work coul d be scaled up to successful full-scale operation, an d to accommodate the operating needs of a full-scale EGU , including

215 http://www.alstom.com/press-centre/2011/5/alstom-a nnouncessucessful-results-of-mountaineer-carbon-capture-and

sequestration-ccs-project //. 216 AEP Mountaineer FEED study, pp 10-11 “CCS front en d engineering & design report: American Electric Powe r Mountaineer CCS II Project. Phase 1”, pp 10-11; available at: http://www.globalccsinstitute.com/publications/aep- mountaineerii-project-front-end-engineering-and-design-feed-re port*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 239 of 854 reliable generating capacity capable of cycling up and down to accommodate consumer demand. Recommended design cha nges to accomplish the desired scaling included detailed fl ue gas specifications, ranges for temperature, moisture an d SO 2 content; careful scrutiny of makeup water composition and te mperature; quality and quantity of available steam to accommod ate heat cycle based on unit load changes; and detailed scru tiny of material and energy balances. 217 See Section V.G.3 below, addressing in more detail the record support for ho w CCS technology can be scaled up to commercial size in b oth pre- and post-combustion applications.

c. Southern Company/MHI Plant Barry

. In June 2011, Southern Company and Mitsubishi Heavy Industries (MHI) launched operations at a 25 MW coa l-fired carbon capture facility at Alabama Power’s Plant Ba rry. The facility, which completed the initial demonstration phase, captured approximately 165,000 metric tons of CO 2 annually at a

CO 2 capture rate of over 90 percent. The facility empl oyed the KM

217 Id. at 11. The EPA does not view this information as being affected by the constraints in EPAct05. The information does not relate to use of technology, level of emission reduction by reason of use of technology, achievement of emissio n reduction by demonstration of technology, or demonstration of a level of performance. The FEED study rather explains engineering challenges which would remain at full scale and how those challenges can be addressed.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 240 of 854 CDR Process, which uses a proprietary high performi ng solvent 218

for CO 2 absorption and desorption that was jointly develop ed by MHI and Japanese utility Kansai Electric Power Co. The captured

CO 2 fromhas been transported via pipeline approximately 12 miles

to the Plant Barry demonstration project was stored underg round in a nearby deep saline geologicCitronelle oil fiel d where it is injected into the Paluxy formation ., a saline reservoir, for storage. 219 Project participants have reported that “[t]he plan t performance was stable at the full load condition w ith CO 2 capture rate of 500 TPD at 90 percent CO 2 removal and lower steam consumption than conventional capture processes.” 220

E. Pre-Combustion Carbon Capture As described earlier, the EPA does not find that IG CC technology – either alone or implementing partial CCS – is part of the BSER for newly constructed steam generating EGUs. However, as noted, there may be specific circumstan ces and business plans – such as co-production of chemicals or fertilizers, or capture of CO 2 for use in EOR operations - that encourage greater CO 2 emission reductions than are required by

218 This is the same carbon capture system that is bei ng utilized at the Petra Nova project at the NRG WA Parish plan t. 219 Ivie, M.A. et al.; “Project Status and Research Pl ans of 500 TPD CO 2 Capture and Sequestration Demonstration at Alabama Power’s Plant Barry”, Energy Procedia 37, 6335 (2013). 220 Id.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 241 of 854 this standard. In this section, we describe and jus tify our conclusion that the technical feasibility of pre-co mbustion carbon capture is adequately demonstrated, indicati ng that this could be a viable alternative compliance pathway. F irst, we explain the technology of pre-combustion capture. W e then describe EGUs that have previously utilized or are currently utilizing pre-combustion carbon capture technology. This discussion is complemented by other sections that c onclude the technical feasibility of other aspects of partial C CS are adequately demonstrated – namely, post-combustion c arbon capture (Section V.D) and sequestration (Sections V.M and V .N). Further, this section’s conclusions are reinforced by Sectio n V.F, in which we identify commercial vendors that offer CCS performance guarantees as well as developers that have publicly stated their confidence in CCS technologies. 1. Pre-combustion Carbon Capture – How it Works Pre-combustion capture systems are typically used w ith IGCC processes. In a gasification system, the fuel (usua lly coal or petroleum coke) is heated with water and oxygen in an oxygenlean environment. The coal (carbon), water and oxyg en react to form primarily a mixture of hydrogen (H 2 ) and carbon monoxide (CO) known as synthesis gas or syngas according to the following high temperature reaction:

3C + H 2 O + O 2  H 2 + 3CO*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 242 of 854 In an IGCC system, the resulting syngas, after remo val of the impurities, can be combusted using a convention al combustion turbine in a combined cycle configuration (i.e., a combustion turbine combined with a heat recovery steam generatorHRSG and steam turbine). The gasification process also typic ally produces

some amount of CO 2 221 as a by-product along with other gases (e.g., H 2 S) and inorganic materials originating from the coa l (e.g., minerals, ash). The amount of CO 2 in the syngas can be increased by “shifting” the composition via the cat alytic watergas shift (WGS) reaction. This process involves the catalytic reaction of steam (“water”) with CO (“gas”) to form H 2 and CO 2 according to the following catalytic reaction:

CO + H 2 O  CO 2 + H 2 An emission standard that requires partial capture of CO 2 from the syngas could be met by adjusting the level of CO 2 in the syngas stream by controlling the level of syngas “s hift” prior to treatment in the pre-combustion acid gas treatme nt system. If a high level of CO 2 capture is required, then multi-stage WGS reactors will be needed and an advanced hydrogen tu rbine will likely be needed to combust the resulting hydrogen- rich syngas.

221 The amount of CO 2 in syngas depends upon the specific gasifier technology used, the operating conditions, and the fuel used; but is typically less than 20 volume percent (http://www.netl.doe.gov/technologies/coalpower/gas ification/gas ifipedia/4-gasifiers/4-3_syngastable2.html).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 243 of 854 Most syngas streams are at higher pressure and can contain higher concentrations of CO 2 (especially if shifted to enrich the concentration). As such, the pre-combustion capture systems can utilize physical absorption (physisorption) solvent s rather than the chemical absorptions solvents described earlier . Physical absorption has the benefit of relying on weak inter molecular interactions and, as a result, the absorbed CO 2 can often be released (desorbed) by reducing the pressure rather than by adding heat. Pre-combustion capture systems have be en used widely in industrial processes such as natural gas processing. Additional information on pre-combustion carbon cap ture can be found in a summary technical support document. 222

2. Pre-combustion Carbon Capture Projects that have not Received DOE Assistance Throughthrough EPAct05 or Tax Credits under IRC Section 48A a. Dakota Gasification Great Plains Synfuels Plant

. Each day , the Dakota Gasification’sGasification Great Plains Synfuels Plant uses approximately 18,000 ton s of North Dakota lignite in a coal gasification process whichthat produces syngas (a mixture of carbon monoxide, carbon dioxideCO, CO 2 , and hydrogen)H 2 ), which is then converted to methane gas (synthetic

222 Technical Support Document – “Literature Survey of Carbon Capture Technology”, available in the rulemaking do cket (Docket ID: EPA-HQ-OAR-2013-0495).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 244 of 854 natural gas) using a methanation process. Each day , the process produces an average of 145 million cubic feet of sy nthetic natural gas that is ultimately transported used for use in home heating and electricity generation. 223 Capture of CO 2 from the facility began in 2000. The Synfuels Plant, using a pre-combustion RECTISOLRectisol ® process, captures about 3 million tons of CO 2 per year - more CO 2 from coal conversion than any facility in the world, and is a participant in the world's largest carbon sequestra tion project. On average about 8,000 metric tons per day of captu red CO 2 from the facility is sent through a 205-mile pipeline to oil fields in Saskatchewan, Canada, where it is used for EOR o perations that result in permanent CO 2 geologic storage. The geologic sequestration of CO 2 in the oil reservoir is monitored by the International Energy Agency (IEA) Weyburn CO 2 Monitoring and Storage Project. Several commenters to the January 2014 proposal arg ued that the Great Plains Synfuels facility is not an E GU, that it operates as a chemical plant, and that its experien ce is not translatable to an IGCC using pre-combustion carbon capture technology. The commenters noted that the Dakota fa cility can be operated nearly continuously without the need to ad just

223 http://www.dakotagas.com/Gasification //.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 245 of 854 operations to meet cyclic electricity generation de mands. In the January 2014 proposal , the EPA had noted that , while the facility is not an EGU, it has significant similari ties to an

IGCC , and that the implementation of the pre-combustion capture technology would be similar enough for comparison. See 79 FR at 1435-36 and n. 11. We continue to hold this view. As explained above, in an IGCC gasification system, coal (or petroleum coke) is gasified to produce a synthe sis gas comprised of primarily of carbon monoxide (CO), hydrogen (H 2 )CO,

H 2 , and some amount of CO 2 (depending on the gasifier and the specific operating conditions). A water-gas-shift r eaction using water (H 2 O, steam) is then used to shift the syngas to CO 2 and

H 2 . The more the syngas is “shifted ”,” the more enriched it becomes in H 2 . In an IGCC, power can be generated by directly combusting the un-shifted syngas in a conventional combustion turbine. If the syngas is shifted such that the res ulting syngas is highly enriched in H 2 , then a special, advanced hydrogen turbine is needed. If CO 2 is to be captured, then the syngas would need to be shifted either fully or partially, depending upon the level of capture required. 224 The Dakota Gasification process bears essential similarities to the just-described IGCC gasificatio n system. As

224 “Cost and Performance of PC and IGCC for a Range o f Carbon Capture”, Rev 1 (2013), DOE/NETL-2011/1498.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 246 of 854 with the IGCC gasification system, the Dakota Gasif ication facility gasifies coal (lignite) to produce a synga s which is then shifted to increase the concentration of CO 2 and to produce the desired ratio of CO and H 2 . As with the IGCC gasification system, the CO 2 is then removed in a pre-combustion capture system, and the syngas that results is made further use of. For present purposes, it is only the manner in which the syngas is

used that distinguishes the IGCC gasification system from th e Dakota Gasification facility. In the IGCC process, the syngas is combusted. In the Dakota Gasification facility, the syngas is processed through a catalytic methanation process w here the CO

and H 2 react to produce CH 4 (methane, synthetic natural gas) and water. Importantly, the CO 2 capture system that is used in the Dakota Gasification facility can readily be used in an IGCC EGU. There is no indication that the RECTISOL® process ( or other similar physical gas removal systems) is not feasib le for an IGCC EGU. In confirmation, according to product lit erature, RECTISOL®, which was independently developed by Lin de and Lurgi, is frequently used to purify shifted, partially shi fted or unshifted gas from the gasification of coal, lignite, and residual oil. 225

225 www.lindeengineering.com/en/process_plants/hydrogen_and_synt hesis_gas_pla nts/gas_processing/rectisol_wash/index.html

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 247 of 854 b. International projects

. There are some international projects that are in v arious stages of development that indicate confidence by the developers in the technical feasibility of pre-combustion carb on capture. Summit Carbon Capture, LLC is developing the Caledo nia Clean Energy Project, a proposed 570-megawatt IGCC plant with 90 percent CO 2 capture that would be built in Scotland, U.K. Captured CO 2 from the plant will be transported via on-shore an d sub-sea pipeline to a subseafor sequestration in a saline formation in the North Sea for sequestration . The U.K. Department of Energy & Climate Change (DECC) recent ly announced funding to allow for feasibility studies on a proposed 570- megawatt, IGCC power plant that would include CCSfo r this plant. 226 Commercial operation is expected in 2017

. 227 The China Huaneng Group – with multiple collaborato rs, including Peabody Energy, the world’s largest priva te sector coal company - is building the 400 MW GreenGen IGCC facility in Tianjin City, China. The goal is to complete the po wer plant before 2020. Over 80 percent of the CO 2 will be separated using

226 http://www.downstreambusiness.com/item/Summit-Powe r-WinsFunding-Studies-Proposed-IGCC-CCS-Project_140878. 227 http://www. downstreambusinesssummitpower .com/ item/SummitPower-Wins-Funding-Studies-Proposed-IGCC-CCSProject_140878projects/carbon-capture/.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 248 of 854 pre-combustion capture technology. The captured CO 2 will be used for EOR operations. 228 Vattenfall and Nuon’s pilot project in Bugennum, Th e Netherlands involves carbon capture from a coal- and biomassfired IGCC plants. It has operated since 2011. 229 Approximately 100 tons of CO 2 per day are captured from a coal- and petcoke-fired IGCC plant in Puertollano, Spain. The facility began operating in 2010. 230 Emirates Steel Industries is expected to capture approximately 0.8Mt of CO 2 per year from a steel-production facility in the United Arab Emirates. Full-scale op erations are scheduled to begin by 2016. 231

228 http://sequestration.mit.edu/tools/projects/greeng en.html

. 229 Buggenum Fact Sheet: Carbon Dioxide Capture and St orage Project, Carbon Capture & Sequestration Technologie s @ MIT, http://sequestration.mit.edu/tools/projects/buggenu m.html (last visited ).. 230 Puertollano Fact Sheet: Carbon Dioxide Capture and Storage Project, Carbon Capture & Sequestration Technologie s @ MIT, https://sequestration.mit.edu/tools/projects/ puertollanopuertoll anto .html (last visited ).. 231 ESI CCS Project Fact Sheet: Carbon Dioxide and Sto rage Project, Carbon Capture & Sequestration Technologie s @ MIT, http://sequestration.mit.edu/tools/projects/esi-ccs -project (last visited ).and https://www.globalccsinstitute.com/projects/large-s cale-ccsprojects.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 249 of 854 The Uthmaniyah CO 2 EOR Demonstration Project in Saudi Arabia will capture 0.8 Mt of CO 2 from a natural gas processing plant over three years. It is expected to begin operating in 2015. 232 The experience of the Dakota Gasification facility, coupled with the descriptions of the technology in the lite rature, the statements from vendors, and the experience of faci lities internationally, are sufficient to support our dete rmination that the technical feasibility of CCS for an IGCC f acility is adequately demonstrated. The experience of addition al facilities, described next, provides additional sup port. 3. Pre-combustion Carbon Capture Projects that have Received DOE Assistance Throughthrough EPAct05 , but did not Receive Tax Credits under IRC Section 48A a. Coffeyville Fertilizer

. Coffeyville Resources Nitrogen Fertilizers, LLC, ow ns and operates a nitrogen fertilizer facility in Coffeyvi lle, Kansas. The plant began operation in 2000 and is the only o ne in North America using a petroleum coke-based fertilizer pro duction process. The petroleum coke is generated at an oil refinery adjacent to the plant. The petroleum coke is gasifi ed to produce

232 Utmaniyah CO 2 EOR Demonstration Project, Global CCS Institute, http://www.globalccsinstitue.com/project/uthmaniyah -co2-eordemonstration-project-0 (last visited )..*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 250 of 854 a hydrogen rich synthetic gas, from which ammonia a nd urea ammonium nitrate fertilizers are subsequently synth esized. As a by

‐ product of manufacturing fertilizers, the plant als o produces significant amounts of CO 2 . In March 2011, Chaparral Energy announced a long-term agreement for the purc hase of captured CO 2 which is transported 68 miles via CO 2 pipeline for use in EOR operations in Osage County, OK. Injectio n at the site started in 2013. At least one commenter suggested that the cost and complexity of carbon capture from these and other i ndustrial projects was significantly decreased because the so urces already separate CO 2 as part of their normal operations. The EPA finds this argument unconvincing. The Coffeyville process involves gasification of a solid fossil fuel (pet coke), shi fting the resulting syngas stream, and separation of the resu lting CO 2 using a pre-combustion carbon capture system. These are the same, or very similar, processes that are used in a n IGCC EGU. The argument is even less convincing when consideri ng that the Coffeyville Fertilizer process uses the SelexolTM pr e-combustion capture process – the same process that Mississippi Power described as having been “in commercial use in the chemical industry for decades” and is expected by Mississipp i Power to “pose little technology risk” when used at the Kemp er IGCC EGU.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 251 of 854 4. Pre-combustion Carbon Capture Projects that have Received DOE Assistance Throughthrough EPAct05 and Tax Credits Underunder IRC Section 48A

a. Kemper County Energy Facility. facility Southern Company’s subsidiary Mississippi Power has constructed the Kemper County Energy Facility in Ke mper County, MS. This is a 582 MW IGCC plant that will utilize l ocal Mississippi lignite and includes a pre-combustion c arbon capture system to reduce CO 2 emissions by approximately 65 percent. The pre-combustion solvent, SelexolTM has also been used extensively for acid gas removal (including for CO 2 removal) in various processes. In filings with the Mississippi Public S ervice Commission for the Kemper project, Mississippi desc ribed the carbon capture system: The Kemper County IGCC Project will capture and com press approximately 65% of the Plant's CO 2 [...] a process referred to as SelexolTM is applied to remove the CO 2 such that it is suitable for compression and delivery to the sequestration and EOR process. [...} The carbon capture equipment and processes proposed in this project ha ve been in commercial use in the chemical industry for decades and pose little technology risk. (emphasis added) 233

233 Mississippi Power Company, Kemper County IGCC Cert ificate Filing, Updated Design, Description and Cost of Kem per IGCC Project, Mississippi Public Service Commission (MPS C) DOCKET NO. 2009-UA-0014, filed December 7, 2009.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 252 of 854 Thus, Mississippi Power believes that, because the SelexolTM process has been in commercial use in the chemical industry for decades, it is well proven, and will pose little te chnical risk when used in the Kemper IGCC EGU. b. Texas Clean Energy Project and Hydrogen Energy C alifornia Project. project The Texas Clean Energy Project , (TCEP), a 400 MW IGCC facility located near Odessa, Texas will capture 90 percent of its CO 2 , which is approximately 3 million metric tons annu ally. The captured CO 2 will be used for EOR in the West Texas Permian Basin. Additionally, the plant will produce urea an d smaller quantities of commercial-grade sulfuric acid, argon , and inert slag, all of which will also be marketed. Summit ha s announced that they expect to commence construction on the pr oject in 2015. 234 The facility will utilize the Linde Rectisol® gas cleanup process to capture carbon dioxide 235 – the same process that has been deployed for decades, including at th e Dakota Gasification facility

. 236 , a clear indication of the developer’s confidence in that technology and further evidence that the Dakota Gasification carbon capture technology is tr ansferable to

EGUs.

234 “Odessa coal-to-gas power plant to break ground th is year”, Houston Chronicle (April 1, 2015). 235 http://www.texascleanenergyproject.com/project/. 236 http://www.texascleanenergyproject.com/project/*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 253 of 854 Hydrogen Energy California, LLC (HECA), is proposin g to build an IGCC facility similar to TCEP in western K ern County, California. The HECA IGCC plant will be fueled by c oal and petroleum coke that will produce 300 MW of power an d will capture CO2 for use in EOR operations. They expect to capture approximately 90 percent of the produced CO2. HECA also intends to employ the Rectisol® process for carbon capture. 237 Neither of these facilities has been constructed; s o they do not provide direct evidence of technical feasibi lity. However, they both plan to employ the same carbon c apture technology that is used at the Dakota Gasification facility and provide a clear indication that project developers have confidence in that technology. F. Vendor Guarantees, Industry Statements, Academic Literature, and Commercial Availability In this section, we describe additional information that supports our determination that CCS is adequately d emonstrated to be technically feasible. This includes performan ce guarantees from vendors, public statements from industry offic ials, and review of the literature.

237 http://energy.gov/fe/hydrogen-energy-california-pr oject*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 254 of 854

1. Performance Guarantees The D.C. Circuit made clear in its first cases conc erning CAA section 111 standards, and has affirmed since t hen, that performance guarantees from vendors are an importan t basis for supporting a determination that pollution technolog y is adequately demonstrated to be technically feasible. In 1973, in Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 440 (D.C. Cir. 1973), the Court (upholdingupheld standards of performance for coal-fired steam generators based on “prototype tes ting data and full-scale control systems, considerations of avail able fuel supplies, literature sources, and documentation of manufacturer guarantees and expectations ”)(”( emphasis supplied )”).)). 238 Subsequently, in Sierra Club v. Costle, the Court noted, in upholding the standard: “we find it informative tha t the vendors of FGD equipment corroborate the achievability of t he

standard.” 239

238 See also Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375, 401-02 (D.C. Cir. 1973) (“It would have been entire ly appropriate if the Administrator had justified the standards ... on testimony from experts and vendors made part of the record.”). 239 Sierra Club v. Costle , 657 F.2d 298, 364 (D.C. Cir. 1981). See also National Petrochem & Refiners Assn v. EPA , 287 F. 3d 1130, 1137 (D.C. Cir 2002) (noting that vendor guar antees are an indicia of availability and achievability of a tech nology-based standard since, notwithstanding a desire to promote sales, “a manufacturer would risk a considerable loss of repu tation if its technology could not fulfill a mandate that it had persuaded EPA to adopt”).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 255 of 854 Linde and BASF offer performance guarantees for CCScarbon capture technology. The two companies are jointly marketin g new, advanced technology for capturing CO 2 from low pressure gas streams in power or chemical plants. In product lit erature , 240 they note that Linde is offeringwill provide a turn-key carbon capture plants whileplant using a scrubbing process and sol vents developed by BASF is, one of the world’s leading technical suppliersuppliers for gas treatment. According to their literature, the companies are making commercially a vailable post-combustion capture technology for lignite and hard coal fired power plants, and are offering “proven and te sted

processes including guarantees” (emphasis added).They further

note that: The captured carbon dioxide can be used commercially for example for EOR (enhanced oil reco very) or as a building block for the production of urea. Alternatively it can be stored underground as a car bon abatement measure. [...] The PCC (Post-Combustion Capture) technology is now commercially available for lignite and hard coal fired power plant [...] applications. The alliance between Linde, a world-leading gases and engineering company and BASF, the chemical comp any, offers great benefits [...] Complete capture plants including CO 2 compression and drying ... Proven and tested processes including guarantee ... Synergies between process, engineering, construction and operation ...

27197 www.intermediates.basf.com/chemicals/web/gastreatment/en/function/conversions:/publish/content/ products-andindustries/gas-treatment/images/Linde_and_BASFFlue_Gas_Carbon_Capture_Plants.pdf.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 256 of 854 Optimized total and operational costs for the owner

. (emphasis added) In addition, other well-established companies that either offer technologies that are actively marketed for C O 2 capture from fossil fuel-fired power plants or that develop those power plants, have publicly expressed confidence in the t echnical feasibility of CCS.carbon capture. For example, Fluor has developed patented CO 2 recovery technologies to help its clients reduce GHG emissions. The Fluor product literature 241 specifically points to the Econamine FG Plus SM (EFG+) process , which uses an amine solvent to capture and produce food grade CO 2 from post-combustion sources. The literature furthe r notes that Econamine FG Plus SM ( EFG +)+ is also used for carbon capture and sequestration projects, that the proprietary techno logy provides a proven, cost-effective process for the removal of CO 2 from power plant flue gas streams , and that the process can be customized to meet a power plant's unique site requ irements, flue gas conditions, and operating parameters. Fluor has also published an article titled “Commerc ially Available CO 2 Capture Technology” in which it describes the EFG+ technology. 242 The article notes, “Technology for the removal of

241 www.fluor.com/client-markets/energy-chemicals/Page s/carboncapture.aspx . 242 http://www.powermag.com/commercially-available-co2 -capturetechnology //.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 257 of 854 carbon dioxide (CO 2 ) from flue gas streams has been around for quite some time. The technology was developed not t o address the greenhouse gasGHG effect but to provide an economic source of CO 2 for use in enhanced oil recovery and industrial pur poses, such as in the beverage industry.” Mitshubishi Heavy Industries (MHI) offers a CO 2 capture system that uses a proprietary energy-efficient CO 2 absorbent called KS-1TM. Compared with the conventional monoet hanolamine (MEA)-based absorbent, KS-1TM solvent requires less solvent circulation to capture the CO 2 and less energy to recover the captured CO 2 . In addition, Shell has developed the CANSOLV CO 2 Capture System, which Shell describes in its product litera ture 243 as a world leading amine based CO 2 capture technology that is ideal for use in fossil fuel-fired power plants where eno rmous amounts of CO 2 are generated. The company also notes that the tec hnology can help refiners, utilities , and other industries lower their carbon intensity and meet stringent greenhouse gasGHG abatement regulations by removing CO 2 from their exhaust streams, with the added benefit of simultaneously lowering SO 2 and NO 2 emissions.

243 http:// www.shell.com/global/products-services/solutions-fo rbusinesses/globalsolutions/shell-cansolv/shell-cans olvsolutions/co2-capture.html

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 258 of 854 Other companies are at various stages of developing and demonstrating processes to remove CO 2 from flue gas streams. At least one commenter suggested that it is unlikel y that any vendor is willing or able to provide guarantees of the performance of the system as a whole, arguing that this shows the system isn’t adequately demonstrated. 244 However, this suggestion is inconsistent with the performance gua rantees offered for other air pollution control equipment. Particulate matter (PM) is controlled in the flue gas stream of a coal-fired power plant using fabric filters or electrostatic p recipitators (ESP). The captured PM is then moved using PM/ash h andling systems and is then transported for storage or re-u se. It is unlikely that a fabric filter or ESP vendor would p rovide a performance guarantee for “the system as a whole.” Similarly, a wet-FGD scrubber vendor would not be expected to pr ovide a performance guarantee for handling, transportation, and re-use of scrubber solids for gypsum wallboard manufacturi ng. CO 2 capture, transportation, and storage should, simila rly, not be viewed as a single technology. Rather, these should be viewed as components of an overall system of emission reducti on. Different companies will have expertise in each of these comp onents, but

244 Comments of Murray Energy, p. 73, EPA-HQ-OAR-2013- 0495-10046.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 259 of 854 it is unlikely that a single technology vendor woul d provide a guarantee for “the system as a whole.” 2. Academic and Other Literature Climate science and climate change mitigation options – includeincluding CCS - are the subject of great academic interest , and there is a large body of academic literature on the subjects exitsthese options and their technical feasibility

. In addition, other research organizations (e.g., U. S. national laboratories and others) have also published studie s on these subjects . that demonstrate the availability of these technologies. A compendium of relevant literature is provided in a Technical Support Document available in the rulem aking

docket. 245 3. Additional Statements by Technology Developers The discussion above of vendor guarantees, positive statements by industry officials, and the academic literature supports the EPA’s determination that partial CCS i s adequately demonstrated to be technically feasible. Industry o fficials have made additional positive statements in conjunction with facilities that received DOE assistance under EPAct 05 or the IRC

245 Technical Support Document – “Literature Survey of Carbon Capture Technology”, available in the rulemaking do cket (Docket ID: EPA-HQ-OAR-2013-0495).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 260 of 854 sectionSection 48A tax credit – these. These statements provide further, although not necessary, support. For example, Southern Company’s Mississippi Power h as stated that the fact, because the SelexolTM process has been used in industry for decades minimized, the technical risk of its use at the Kemper IGCC facility is minimized . For example:

The carbon capture process being utilized for the Kemper County IGCC is a commercial technology refer red to as SelexolTM. The SelexolTM process is a commercia l technology that uses proprietary solvents, but is b ased on a technology and principles that have been in commercial use in the chemical industry for over 40 years. Thus, the risk associated with the design an d operation of the carbon capture equipment incorpora ted into the Plant’s design is manageable. 246 And ...

“ The carbon capture equipment and processes proposed in this project have been in commercial us e in the chemical industry for decades and pose little technology risk .”

. 247

Similarly, in an AEP Second Quarter 2011 Earnings Conference Call, Chairman and CEO Mike Morris said of the Mountaineer CCS project:

“ We are encouraged by what we saw, we’re clearly impressed with what we learned, and we feel that we have demonstrated to a certainty that the carbon capture and

246 Testimony of Thomas O. Anderson, Vice President, G eneration Development for Mississippi Power, MS Public Servic e Commission Docket 2009-UA-14 at 22 (Dec. 7, 2009). 247 Mississippi Power Company, Kemper County IGCC Cert ificate Filing, Updated Design, Description and Cost of Kem per IGCC Project, Mississippi Public Service Commission (MPS C) DOCKET NO. 2009-UA-0014, filed December 7, 2009.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 261 of 854 storage is in fact viable technology for the United States and quite honestly for the rest of the world going forward .”

. 248

Some commenters have claimed that CCS technology is not technically feasible, and some further assert that vendors do not offer performance guarantees. For example, Alst om commented:

The EPA referenced projects fail to meet the 'technically feasible' criteria. These technologies are not operating at significant scale at any site as o f the rule publication. We do not support mandating techn ology based on proposed projects (many of which may never be built). 249

As discussed above, in fact, vendors do in fact offer performance guarantees. MoreoverWe further note that , as noted above, Boundary Dam Unit #3 is a full-scale project that is successfully implementing full CCS with post-combus tion capture, and Dakota Gasification is likewise a full-scale co mmercial operation that is successfully implementing pre-com bustion CCS technology. Moreover, as we explain above, this tec hnology and performance is transferable to the steam electric g enerating sector. In addition, as noted above, technology pro viders and

248 American Electric Power Co Inc AEP Q2 2011 Earning s Call Transcript, Morningstar, http://www.morningstar.com/earnings/28688913-americ an-electricpower-co-incaep-q2-2011-earnings-call-transcript.as px. 249 Alstom Comments, p. 3.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 262 of 854 technology end users have expressed confidence in t he availability and performance of CCS technology. 250 G. Response to Key Comments on the Adequacy of the Technical Feasibility Demonstration 1. Commercial Availability Some commenters asserted that CCS cannot be conside red the BSER because it is not commercially available. Ther e is no requirement, as part of the BSER determination, tha t the EPA finds that the technology in question is “commercia lly available ”..” As we described in the January 2014 proposal, the D.C. Circuit Court has explained that a standard of performance is “achievable” if a technology or other system of emission reduction can reasonably be projected to be available to new sources at the time they are constructed that will allow them to

meet the standard . (, and that there is no requirement that the technology “must be in routine use somewhere.” See Portland

Cement v. Ruckelshaus , 486 F. 2d at 391; 79 FR 1463 ; see also

250 We note that before filing comments for this rule asserting that CCS is not technically feasible, Alstom issued public statements that, like the other industry officials quoted above, affirmed that CCS is technically feasible. Accordin g to an Alstom Power press release, Alstom President Philli pe Joubert, referencing results from an internal Alstom study, stated at an industry meeting: “We can now be confident that car bon capture technology (CCS) works and that it is cost - effective”. http://www.alstom.com/press-centre/2011/6/2011-06-1 6-CCS-costcompetiveness //.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 263 of 854 Section V.C above.) However. In any case , as discussed above, CCS technology is available through vendors who pro vide performance guarantees, which indicates that in fac t, CCS is commercially available, which adds to the evidence that the technology is adequately demonstrated to be technic ally feasible. In sum, “[t]he capture and CO 2 compression technologies have commercial operating experience with demonstra ted ability for high reliability.” 251 2. Must a technology or system of emission reduction be in fullscale use to be considered demonstrated? Commenters maintained that the EPA can only show th at a BSER is “adequately demonstrated” using operating d ata from the technology or system of emission reduction itself. This is mistaken. Since the very inception of the CAA secti on 111 program, courts have noted that “[i]t would have be en entirely appropriate if the Administrator had justified the standard, not on the basis of tests on existing sources or old te st data in the literature, but on extrapolations from this dat a, on a reasoned basis responsive to comments, and on testi mony from experts and vendors ....” Portland Cement v. Ruckelshaus , 486 F.

251 “Cost and Performance Baseline for Fossil Energy P lants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 3 6.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 264 of 854 2d at 401-02. 252 In any event, as discussed above, Boundary Dam has provided data from the operation of the CCS equ ipment itself. In a related argument, other commenters stated that a system cannot be adequately demonstrated unless all of its component parts are operating together. 253 Courts have, in fact, accepted that the EPA can legitimately infer that a technology is demonstrated as a whole based on operation of co mponent parts which have not, as yet, been fully integrated. Sur Contra la Contaminacion v. EPA , 202 F

. 3d 443, 448 (1st Cir

. 2000); Native Village of Point Hope v Salazar 680 F

. 3d 1123, 1133 (9th Cir. 2012 ). Moreover, all components of CCS are fully integr ated at Boundary Dam: post-combustion full CCS is being uti lized at a steam electric fossil fuel-fired plant, with captur ed carbon

252 More recently, the D.C. Circuit stated: Our prior decisions relating to technology-forcing standards are no bar to this conclusion. We recogni ze here, as we have recognized in the past, that an agency may base a standard or mandate on future technology when there exists a rational connection between the regulatory target and the presumed innovation.

API v. EPA , 706 F. 3d at 480 (D.C. Cir 2013) (citing the sect ion 111 case Sierra Club v. Costle , 657 F. 2d at 364). The Senate Report to the original section 111 likewise makes c lear that it was not intended that the technology “must be in ac tual routine use somewhere.” Rather, the question was whether t he technology would be available for installation in new plants. S. Rep. No. 991 -1196, 91 st Cong., 2d Sess. 16 (1970). 253 See , e.g .., Comments of UARG p. 5.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 265 of 854 being transported via dedicated pipeline to both se questration and EOR sites. All components are likewise demonstr ated for precombustion full CCS at the Dakota Gas IGCC facility , except that the facility does not generate electricity, a disti nction without a difference for this purpose (see Section V.E.2.a

above ). The short of it is that the “EPA does have authorit y to hold the industry to a standard of improved design and operational advances, so long as there is substanti al evidence that such improvements are feasible and will produc e the improved performance necessary to meet the standard .” Sierra

Club , 657 F. 2d at 364. The EPA’s task is to “identify the major steps necessary for development of the device, and give plausible reasons for its belief that the industry will be able to solve those problems in the time remaining”. API v. EPA , 706 F. 3d at 480 (quoting NRDC v. EPA . , 655 F. 2d 318, 333 (D.C. Cir. 1981), and citing Sierra Club for this proposition). 3. Scalability of Pilot and Demonstration Projects Commenters maintained that the EPA had no basis for maintaining that pilot and demonstration plant oper ations showed that CCS was adequately demonstrated. This is mista ken. In a 1981 decision, Sierra Club v. Costle , the D.C. Circuit explained that data from pilot-scale, or less than full-scale operation, can be shown to reasonably demonstrate performance at full-scale*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 266 of 854 operation, although it is incumbent on the EPA to e xplain the necessary steps involved in scaling up a technology and how any obstacles may reasonably be surmounted when doing s o. 254 The EPA

has done so here. Most obviously, the final standard reflects experie nce of full-scale operation of both pre- and post-combustion carbon capture. Pre-combustion carbon capture is likewise demonstr ated

at full-scale. Second, the record explains in detail how CCS can be implemented at full-scale. The NETL cost and per formance reports, indeed, contain hundreds of pages of detai led, documented explanation of how CCS can be implemente d at fullscale for both utility boiler and IGCC facilities. See, for example, the detailed description of the following systems projected to be needed for a new supercritical PC b oiler to capture CO 2 : coal and sorbent receiving and storage, steam generator and ancillaries, NO X control system, particulate

254 Sierra Club v. Costle , 657 F. 2d 298, 341 n.157 and 380-84 (D.C. Cir. 1981). See also Essex Chemical Corp. v. EPA, 486 F. 2d at 440 (upholding achievability of standard of p erformance for coal-burning steam generating plants which hadn ’t been achieved in full-scale performance based in part on “prototype testing data” which, along with vendor guarantees, indicated that the promulgated standard was achievable); Weyerhaeuser v. Costle , 590 F. 2d 1054 n. 170 (D.C. Cir. 1978) (use of pi lot plant information to justify technology-based stand ard for Best Available Technology Economically Achievable under section 304 of the Clean Water Act); FMC Corp. v. Train , 539 F. 2d 973, 983- 84 (4 th Cir. 1976)(same).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 267 of 854 control, flue gas desulfurization, flue gas system, CO 2 recovery facility, steam turbine generator system, balance o f plant, and accessory electric plant, and instrumentation and c ontrol systems. 255 The DOE/NETL is explicit that its studies confirm t he technical feasibility of CCS, stating, in relevant part, that t he “studies ... establish estimates for the cost and p erformance of combustion and gasification based power plants ... with ... carbon dioxide capture and storage. Several ranks of coal are being assessed in process configurations that are b ased on technology that could be constructed today such tha t the plant could be operational in the 2012 - 2015 timeframe.” 256 It is important to note that, while some commenters challenged the EPA’s use of costs in the DOE/NETL cost and performance reports, commenters did not challenge t he technical methodology in the work. In addition, the AEP FEED study indicates how the development scale post-combustion CCS could be succ essfully scaled up to full - scale operation. See Section V.D.3.b above.

255 See NETL pp. 57-74. Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity; Revision 2a, pp. 57-74. 256 http://www.netl.doe.gov/research/energy-analysis/ energybaseline-studies*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 268 of 854 Tenaska Trailblazer Partners, LLC also prepared a F EED study 257 for the carbon capture portion of the previously proposed Trailblazer Energy Center, a 760 MW SCPC E GU that was proposed to include 85 to 90 percent CO 2 post-combustion capture. Tenaska selected the Fluor Econamine FG Plus SM technology and contracted Fluor to conduct the FEED study. One of the goals of the FEED study was to “[c]onfirm that scale up to a large commercial size is achievable.” Tenaska ultimately concluded that the study had achieved its objectives resultin g in “[c]onfirmation that the technology can be scaled u p to constructable design at commercial size through (1) process and discipline engineering design and CFD (computationa l fluid dynamics) analysis, (2) 3D model development, and ( 3) receipt of firm price quotes for large equipment.” Much has been written about the complexities of add ing CCS systems to fossil fuel-fired power plants. Some of these statements come from high government officials. Some commenters argued that the EPA minimized – or even ignored - those complexities– these publically voiced concerns in the discussion presented in the January 2014 proposal. On the cont rary, the EPA has not minimized or ignored these complexities . In, but it is

257 Final front-end engineering design (FEED) study re port”, available at: www.globalccsinstitute.com/publicatio ns/tenaskatrailblazer-front-end-engineering-design-feed-study

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 269 of 854 important to realize that most of these statements come in a different context: namely, implementing full CCS, o r retrofitting CCS onto existing power plants. For ex ample, in the Final Report of the President’s CCS Task Force, it was noted that “integration of CCS technologies with the powe r cycle at generating plants can present significant cost and operating issues that will need to be addressed to facilitate widespread, cost-effective deployment of CO 2 capture.” 258 This statement – and most of the statements in this vein – are in refere nce to implementation of full CCS systems that capture mor e than 90 percent of the CO 2 . and many reference widespread implementation of such technology. The EPA has addressed the concerns regarding “significant cost” by finalizing a standard that re lies on partial CCS which we show, in this preamble and in the

258 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 28. Report of the Inter agency Task Force on Carbon Capture and Storage (August 2010), page 28. See also DOE Carbon Capture Website: “First generation CO 2 capture technologies are currently being used in various in dustrial applications. However, in their current state of d evelopment, these technologies are not ready for implementation on coalbased power plants because they have not been demon strated at appropriate scale, requisite approximately one-thir d of the plant’s steam power to operate, and are cost prohib itive.” (Dec 2010); and Testimony of Dr. S. Julio Friedmann, Dep uty Asst. Secretary of Energy for Clean Coal, US Dept. of Ene rgy, before the Subcommittee on Oversight and Investigations Co mmittee on Energy and Commerce (Feb. 11, 2014): CCS technologi es at new coal-fired plants would result in "something like a 70 to 80 percent increase on the wholesale price of electric ity."*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 270 of 854 supporting record, can be implemented at a reasonab le , nonexorbitant cost. The Boundary Dam facility, in particular, demonstrates that the complexities of implementing CCS – even full CCS – can be overcome. cost. Concerns regarding “operating issues” are also ofte n associated with implementation of full CCS – and of ten with implementation of full CCS as a retrofit to an exis ting source. The EPA addresses technical feasibility of partial CCS in this final action. The Boundary Dam facility, in particular, demonstrates that the complexities of implementing CCS – even full CCS – can be overcome. Many of the challenges that are often noted are only issues for implementation of C CS retrofits for existing sources. Implementation of CCS at some existing sources may be challenging because of space limitat ions. That should not be an issue for a new facility because t he developer will need to ensure that adequate space is availabl e during the design of the facility. Constructing CCS technology at an existing facility can be challenging even if there is adequate space because the positioning of the equipment may be awkward when it must be constructed to fit with the existin g equipment at the plant. Some commenters noted the challenges of diverting steam from the plant’s steam cycle. Again, that is primarily an issue with full CCS implementation as a retrofit to an existing source. Consideration of steam requirements for sol vent*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 271 of 854 regeneration can be factored into the design of a n ew facility. We also note that issues of integration with the pl ant’s steam cycle are less challenging when implementing partia l CCS. Some commenters noted conclusions and statements fr om the CCS Task Force report as contradictory to the EPA’s determination of that partial CCS is technically fe asible and adequately demonstrated. However, the EPA mentioned in the January 2014 proposal , and we emphasize again here , that the Task Force was charged with proposing a plan to ove rcome the barriers to the widespread, cost-effective deployme nt of CCS by 2020. Implicit in all of the conclusions, recommend ations, and statements of that final report is a goal of widesp read implementation of full CCS – including retrofits of existing sources. This final action does not require – nor d oes it envision – the near term widespread implementation of full CCS. On the contrary, as we have noted several times in this preamble, the EPA and others predict that very few , if any, new coal-fired steam generating EGUs will be built in t he near term. Thus, the EPA has provided an ample record supporti ng its finding that partial CCS is feasible at full-scale. As in Sierra

Club , the EPA has presented evidence from full-scale operati on, smaller scale installations, and reasonable, corrob orated technical explanations of how the BSER can be succe ssfully operated at full scale. See 657 F. 2d at 380, 382. Indeed, the*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 272 of 854 EPA has more evidence here, as the baghouse standar d in Sierra

Club was justified based largely on less - than - full - scale operation. See 657 F. 2d at 380 (there was only “limited data from one full scale commercial sized operation ”)”), 376 (“the baghouses surveyed were installed at small plants”) , and 341 n. 157 . ; see also Section V.L, explaining why CCS is a more developed technology than FGD scrubbers were at the inception of the 1971 NSPS for this industry.

H. Consideration of Costs CAA section 111(a) defines “standard of performance ” as an emission standard that reflects the best system of emission reduction that is adequately demonstrated, “taking into account [, [ among other things ,]] the cost of achieving such reduction.” Based on consideration of relevant cost metrics in the context of current market conditions, the EPA concludes that the costs associated with the final standard are reasonable. In reaching this determination, theIn reaching this determination, the EPA considered a host of differe nt cost metrics, each of which illuminated a particular asp ect of cost consideration, and each of which demonstrated that the costs of the final standard are reasonable. The EPA evaluated capital costs on a per-plant basis, responding to public co mment that noted the particular significance of capital costs for fossil steamcoal-fired EGUs. As in the proposal, the EPA also*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 273 of 854 considered how the standard would affect the levelized cost of electricityLCOE for individual affected EGUs as well as national, overall cost impacts of the standard. The EPA found that the anticipated cost impacts are similar to th ose in other promulgated NSPS – including for this industry

--- that have been upheld by the D.C. Circuit. The costs are also comparable to those of other base load technologies that might be selected on comparable energy portfolio diversity grounds. F inally, the EPA does not anticipate any significant overall nationwide costs

or cost impacts on consumers . because projected new generating capacity is expected to meet the standards even in the baseline. Accordingly, after considering costs from a range of different perspectives, the EPA concludes that the costs of the final

standard are reasonable. 1. Rationale at Proposal At proposal, the EPA evaluated the costs of new fossil steamcoal-fired EGUs implementing full (90 percent) and partial CCS. The EPA compared the predicted levelized cost of electricity ( LCOE ) of those units against the LCOE of other new units using dispatchable technologies often considered for new base load power with fuel diversity, primarily incl uding a new nuclear plant, as well as a new biomass-fired EGU. See 79 FR at 1475-78. The levelized cost for a new steam EGU implementing full CCS was higher than thosethat of thesethe other non-NGCC*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 274 of 854 dispatchable technologies, and we did not propose to identify a new steam EGU implementing full CCS as BSER on thisthat basis. Id. at 1477. The EPA determined that the proposed that a standard of performance of 1,100 lb CO 2 /MWh- grossg , reflecting a new steam EGU implementing partial CCS, could be implementedachieved at reasonable cost based on a comparison of the projected LCOE associated with achieving this s tandard with the alternative dispatchable technologies just ment ioned. In the January 2014 proposal, the EPA used LCOE projection s for new fossil fuel-fired EGUs from a series of studies con ducted by the DOE NETL. These studies – the “cost and performance studies” – detail expected costs and performance for a range o f technology options both with and without CCS. 259 The EPA used LCOE projections for non-fossil dispatchable generation – specifically nuclear and biomass – from the EIA AEO 2013. See 79 FR 1435.

259 For the cost estimates in the January 2014 proposa l, the EPA used costs for new SCPC and IGCC units utilizing bi tuminous coal from the reports “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL–2010/1397 (November 2010) and “Cost and Performance of PC and IGCC Plan ts for a Range of Carbon Dioxide Capture”, DOE/NETL–2011/149 8, May 27, 2011. Additional cost and performance information c an be found in additional volumes that are available at http://www.netl.doe.gov/research/energy-analysis/en ergybaseline-studies.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 275 of 854 In addition, the EPA concludedproposed that the costs ofto implement partial CCS were reasonable because a segment of t he industry was already accommodating them. Id. at 1478. The EPA also considered anticipated decreases in the cost o f CCS technologies, the availability of government tax be nefits, loan guarantees, and direct expenditures, and the opport unity to generate income from sale of captured CO 2 for enhanced oil recovery.EOR. Id. at 1478-80. The EPA noted that the proposed standard was not expected to lead to any significan t overall costs or effects on electricity prices. Id. at 1480-81. The EPA also acknowledged the overall market context, notin g that fossil steam EGUs, even without any type of CCS, are signi ficantly more expensive than new natural - gas - fired electricity generation, but that some electricity suppliers might include fossil steam generationnew coal-fired generating sources in their generation portfolio, and would pay a premium to do so. Id. at 1478. 2. Brief Summary of Cost Considerations Underunder CAA Section

111 As explained above, CAA section 111(a) directs the EPA to “tak[e] into account the cost” of achieving reducti ons in determining if a particular system of emission redu ction is the best that is adequately demonstrated. The statute d oes not provide further guidance on how costs should be con sidered, thus affording the EPA considerable discretion in choosi ng a means of*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 276 of 854 cost consideration. In addition, it should be noted that in evaluating the reasonableness of costs, the D.C. Circuit has upheld application of a variety of metrics, such as the amount of control costs or product price increases. See Section III.H.3.(b).(1) above. Following the directive of CAA section 111(a) and applicable precedent, the EPA evaluated relevant me trics and context in considering the reasonableness of the re gulation’s costs. The EPA’s findings demonstrate that the cost s of the selected final standard are reasonable. 3. Current Market Context The EIA projects that few new fossil steamcoal-fired EGUs will be constructed over the coming decade and that those that are built will apply CCS, reflecting the broad cons ensus of government, academic, and industry forecasters. 260 The primary reasons for this projected trend include low electr icity demand growth, highly competitive natural gas prices, and increases in the supply of renewable energy. In particular, USU.S.

260 Even in its sensitivity analysis that assumes high er natural gas prices and electricity demand, EIA does not pro ject any additional coal beyond its reference case until 202 3, in a case where power companies assume no GHGs emission limit ations, and until 2024 in a case where power companies do assum e GHGs emission limitations. EIA, “Annual Energy Outlook 2015,” DOE/EIA-0383(2015), April 2015, “[v]ery little unpl anned coalfired capacity is added across all the AEO 2015 cas es”, p. 26.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 277 of 854 electricity demand growth has followed a downward s loping trend for decades with future growth expected to remain v ery low. 261 Furthermore, the EPA projects that , for any new fossil fuelfired electricity generating capacity that is const ructed through 20202030 , natural gas will be the overwhelming fuel of choice

. 262 See RIA chapter 4

. The EIA’s projection is confirmed by an examination of Integrated Resource Plans (IRPs) contained in a TSD in the docket for this rulemaking. IRPs are used by utilit ies to plan operations and investments in both owned generation and power purchase agreements over long time horizons. Though IRPs do not demonstrate a utility’s intent to pursue a particul ar generation technology, they do indicate the types of new gener ating technologies that a utility would consider for new generating capacity. The EPA’s survey of recent IRPs demonstra tes that across the nation, utilities are not actively consi dering constructing new coal-fired generation without CCS in the near

term. Accordingly, construction of new uncontrolled fossil steamcoal-fired generating capacity is not anticipated in the near term, even in the absence of the standards of performance

261 EIA, “Annual Energy Outlook 2014,” Figure MT-29, May 7, 20142015,” DOE/EIA-0383(2015), April 2015, p. 8

. 262 Integrated Planning Model (IPM) run by the EPA (v. 5.15) Base Case, available at www.epa.gov/powersectormodeling/

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 278 of 854 we are finalizing todayin this rule , except perhaps in certain limited circumstances. In particular, commenters suggested that some devel opers might choose to build a new coal-fired EGU, despite its not being cost competitive, in order to achieve or main tain “fuel diversity.” Public announcements and IRPs also indicate that utilities are interested in a range of technologies that could provide or preserve fuel diversity within generatin g fleets. In particular, fuel diversity could provide important additionalFuel diversity could provide important value by serving as a hedge against the possibility that fut ure natural gas prices will far exceed projected levels. Public announcements, including IRPs, confirm that utilities are interested in technologies that could provide or preserve fuel diversity within generating fleets. T he Integrated

Resource Plan TSD 263 notes examples where the goal of fuel diversity was considered in IRPs; in many cases, th ese plans considered new generation that would not rely on na tural gas. In particular, several utilities that considered fuel diversity in developing their IRPs included new nuclear generati on as a potential future generation strategy.

263 Technical Support Document - “Review of Electric U tility Integrated Resource Plans” (May 2015), available in the rulemaking docket EPA-HQ-OAR-2013-0495.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 279 of 854 In addition, the EPA recognizes that there may be i nterest in constructing a new combined-purpose plantscoal-fired facility that would generate power as well as produce chemic als or carbon dioxideCO 2 for use in enhanced oil recoveryEOR projects. These facilities would similarly provide additional value due to the revenue streams from saleable chemical products or carbon dioxide.CO 2 . 264 As demonstrated below, the agency carefully conside red the reasonableness of costs in identifying a standard t hat allows a path forward for such projects while rejecting more stringent options that would impose excessive costs. and reje cts more stringent options that would impose potentially exc essive costs. In fact, based on this careful consideration of cos ts, the EPA is finalizing a substantially lower cost standard t han the one we proposed. At the same time, we note the unusual circumstances presented here, where the record, and indeed simple consideration of electricity market economics, demo nstrates that non-economic factors such as fuel diversity are lik ely to drive any construction of new coal-fired generation. See also RIA chapter 4 (documenting that electric power companie s will choose to build new EGUs that comply with the regulatory r equirements

264 The EPA may, of course, consider revenues generate d as a result of application of pollution control measures in assessing the costs of a best system of emission reduction. S ee New York v. Reilly , 969 F.2d 1147, 1150-52 (D.C. Cir. 1992).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 280 of 854 of this rule even in its absence, primarily NGCC un its, because of existing and expected market conditions). Under these circumstances, the EPA’s consideration of costs tak es into account that higher costs can be viewed as reasonab le when costs are not a paramount factor in new coal capacity dec isions. At the same time, the EPA acknowledges and agrees with the public comments that such an argument, left unconstrained, could justify any standard and obviate all cost considera tions. 265 The EPA has reasonably cabined its consideration of cos ts by examining costs for comparable non-NGCC base load d ispatchable technologies, as well as by considering capital cos ts and other cost metrics. 266 This cost-reasonable standard will preserve the opportunity for such projects while driving new tec hnology deployment. 267

265 See, e.g., Comments of Murray Energy, pp. 79-80. 266 Indeed, the EPA is not only adopting a standard pr edicated on a lower rate of carbon capture than proposed, but a lso rejecting full CCS for reasons of cost. See Section V.P belo w. Thus, although the EPA has reasonably taken into account the current economic posture of the industry whereby new capaci ty is not cost-competitive and so would be added for non-econ omic reasons, it is not using that fact to negate consideration o f cost here. See also Section V.I.4 below responding to comments that the incremental cost of partial CCS could prove the dif ference between constructing and not constructing new coal capacity. 267 In this rulemaking, our determination that the cos ts are reasonable means that the costs meet the cost stand ard in the case law no matter how that standard is articulated , that is, whether the cost standard is articulated through th e terms that the case law uses, e.g., “exorbitant,” “excessive,” etc., or through the term we use for convenience, “reasonabl eness.”*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 281 of 854

4. Consideration of Capital Costs As noted above, CAA section 111 does not mandate any particular method for evaluating costs, leaving the EPA with significant discretion as to how to do so. One meth od is to consider the incremental capital costs required for a unit to achieve the standard of performance. The EPA included information on capital cost at pro posal

. 268 Extensive and, as discussed further below, the LCOE metric relied upon at proposal and in this final rulemakin g incorporates and fully reflects capital costs. 269 Nonetheless, extensive comment from industry representatives and others n oted persuasively that fossil-steam units are very capital-intensive projects and recommended that a separate metric, solely of capital costs , be considered by the EPA in evaluating the final standard’s costs. Accordingly, the EPA has considered the final standard’s impact on the capital costs of new fossi l-steam generation. The EPA has determined that the increme ntal capital costs of the final standard are reasonable because they are comparable to those in line with prior regulations and to industry experience, and because the fossil steam e lectric power

268 Draft RIA p. 5-20 and Table 5-5. 269 See RIA chapter 4.5.4 and Fig. 4-3; see also “Cost and Performance Baseline for Fossil Energy Plants Suppl ement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (July 2015) p. 17.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 282 of 854 industry has been shown to be able to successfully absorb capital costs of this magnitude in the past. Prior new source performance standards for new foss il steam generation units have had significant – yet managea ble – impacts on the capital costs of construction. The EPA estim ated that the costs for the 1971 NSPS for coal-fired electric generating unitsEGUs were $19M for a 600 MW plant, consisting of $3.6M for particulate matter controls, $14.4M for sulfur diox ide controls, and $1M for nitrogen oxides controls, representing a 15.8 percent increase in capital costs above the $120M c ost of the plant. See 1972 Supplemental Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld the EPA’s determination that the costs associated with the final 1971 standard w ere reasonable, concluding that the EPA had properly ta ken costs into consideration. Essex Cement v. EPA , 486 F. 2d at 440. In reviewing the 19791978 NSPS for fossil steam electric generating unitscoal-fired EGUs , the D.C. Circuit recognized that “EPA estimates that utilities will have to spe nd tens of billions of dollars by 1995 on pollution control un der the new NSPS” and that “[c]onsumers will ultimately bear th ese costs.” Sierra Club , 657 F.2d at 314. The court nonetheless upheld the EPA’s determination that the standard was reasonabl e. Id. at 410.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 283 of 854 The cost and investment impacts of the 1978 NSPS on electric utilities waswere subsequently evaluated in a 1982 Congressional Budget Office (CBO) retrospective stu dy. 270 The CBO study highlighted that installation of scrubbers

--- capital intensive pollution control equipment that had “in effect” been mandated by the 1978 NSPS

--- increased capital costs for new EGUs by 10 to as much as 20 percent. 271 The study further noted that air pollution control requirements in general had led to an estimated a 37.5 to 45 percent increase in capital costs for coal-fired power plant installation between 1971 an d 1980. 272 The study retrospectively confirmed the EPA’s concl usion that imposition of these costs was reasonable, find ing that “utilities with commitments to pollution control te nd to fare no better and no worse than all electric utilities in general.” 273 In assessing the capital cost impacts of the suite of 1970’s1970s EPA air pollution standards, the report concluded that “though controlling emissions is indeed costly , it has not played a major role in impairing the utilities ’ financial position, and is not likely to do so in the future. ” 274

270 Congressional Budget Office , report, “ The Clean Air Act, the Electric Utilities, and the Coal Market ,”, April 1982, p. 10-11, 23. 271 Id. at 10-11. 272 Id. at 22. 273 Id. at xvi. 274 Id.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 284 of 854 In NSPS standards for other sectors, the EPA's determination that capital cost increases were reas onable has similarly been upheld. In Portland Cement Association , the D.C. Circuit upheld the EPA’s consideration of costs for a standard of performance that would increase capital costs by about 12 percent, although the rule was remanded due to an unrelated procedural issue. 486 F.2d at 387-88. Reviewing the EPA’s final rule after remand, the court again upheld the stand ards and the EPA’s consideration of costs, noting that “[t]he in dustry has not shown inability to adjust itself in a healthy e conomic fashion to the end sought by the Act as represented by the standards prescribed.” Portland Cement v. Ruckelshaus , 513 F. 2d 506, 508 (D.C. Cir. 1975). The capital cost impacts incurred under these prior

standards are similarcomparable in magnitude on an individual unit basis to those projected for the present stand ard. We predict that the incremental costs of control for a new highly efficient SCPC unit to meet the final emission limitation of 1,400 lb CO 2 /MWh- grossg would be an increase of 17.321 - 22*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 285 of 854 percent for capital costs. Incremental capital costs of control for a new IGCC unit would be even less. See Table 7 below. 275 ,276 Table 7. Comparison of capital costsEstimated Capital Costs for a newNew SCPC and a newNew SCPC meetingMeeting the final standardFinal Standard of performance.Performance. 277 Total Total Overnight As-Spent Cost Capital Cost ($/(2011$/ kW) (2011$/kW) SCPC - no CCS 2, 452507 2,842 SCPC - partial CCS 2,8763,042 3,458 (1,400 lb CO 2 /MWh- grg )

Incremental cost increase 1721 .3% 21.7%

By comparison, a SCPC that co-fires with natural ga s to meet the final standard of 1,400 lb CO 2 /MWh-g would not result in an increase in capital cost over the uncontrolled S CPC. A compliant IGCC unit co-firing natural gas is predic ted to have Total Overnight Cost of $3,036/kW – an approximatel y 21.1 percent increase in capital over the uncontrolled S CPC unit.

275 We explain at Section V.I.2 and 3 below the reasonableness of the EPA’s cost projections here. 276 We estimate that a new SCPC EGU using low rank coa l (subbituminous coal or dried lignite) would incur a capital cost increase of 23 percent to meet the final standard. See “Achievability of the Standard for Newly Constructe d Steam Generating EGUs” technical support document availab le in the rulemaking docket. 277 Exhibit A-3 (p. 18); “Cost and Performance Baselin e for Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (Ju ne 2015). Inserted Cells

Inserted Cells Inserted Cells*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 286 of 854

5. Consideration of Costs Based on Levelized Cost of E lectricity As in the proposal, the EPA also considered the reasonableness of costs by evaluating the LCOE asso ciated with the final standard. The LCOE is a commonly used eco nomic metric that takes into account all costs to construct and operate a new power plant over an assumed time period and an assu med capacity

factor. The LCOE is a summary metric, which expresses the f ull cost of generating electricity on a per unit basis (i.e., megawatt-hours). Levelized costs are often used to compare the cost of different potential generating sources. Whi le capital cost is a useful and relevant metric for capital- heavyintensive fossil-steam units, the LCOE can serve as a useful complement because it takes into account all specified costs , (operation and maintenance, fuel – as well as capital costs), over the whole lifetime of the project. As previously mentioned, at proposal the EPA relied on LCOE projections for fossil fuel-fired EGUs (with and wi thout CCS) from DOE/NETL reports detailing the results of stud ies evaluating the costs and performance of such units. For nonfossil dispatchable generating sources, the EPA rel ied on LCOE projections from EIA AEO 2013. For this final actio n, the EPA is relying on updated costs from the same sources. The NETL has provided updated cost and performance information i n recently published revisions of reports used in the January 2014*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 287 of 854 proposal. 278 The updated SCPC cases in the reports include up-t odate cost and performance information from recent v endor quotes and implementation of the Shell Cansolv post-combus tion capture process – the process that is currently being utili zed at the Boundary Dam #3 facility. The IGCC cost and perform ance results in the updated reports utilize vendor quotes from t he previous report; the costs are adjusted from $2007 to $2011. Important also to note is that DOE/NETL utilized conventional financing for cases without CCS and utilized high-risk financ ial assumptions for cases that include CCS. 279 Using information from those reports, the DOE/NETL prepared a separate report summarizing a study that evaluate d the cost and performance of various plants designed to meet a range of CO 2 emissions by varying the CO 2 capture rate (i.e., the level of partial capture). 280 The EIA also updated LCOE projections from

278 “Cost and Performance Baseline for Fossil Energy P lants: Volume 1a” Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3, U.S. DOE NETL report (2015) and “Cost a nd Performance Baseline for Fossil Energy Plants: Volu me 1b: Bituminous Coal (IGCC) to Electricity, Revision 2 – Year Dollar Update, U.S. DOE NETL report (2015). Both reports a re available at www.netl.doe.gov/research/energy-analysis/energy -baselinestudies. 279 Cost and Performance Baseline for Fossil Energy Pl ants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015) p. 18. 280 “Cost and Performance Baseline for Fossil Energy P lants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015). Available at*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 288 of 854 AEO 2013 to AEO 2014 and again in AEO 2015. Those a re discussed in more detail in Section V.I.2.b and d. In evaluat ing costs for the final standards in this action, the EPA relied primarily on the updated NETL LCOE projections for new fossil fu el-fired EGUs provided in the reports described above and on the LCOE projections for non-fossil, dispatchable generating options from the EIA’s AEO 2015. 281 Here, the EPA compared the LCOE of the final standard to the LCOE of analogous potential s ources of intermediate and base load power. This comparison d emonstrated that the LCOE for a fossil steam unit with partial CCS is within the range of that forthe LCOE of comparable alternative non-NGCC generation sources. In particular, nuclear and biom ass generation, which similarly provide both base load power and fuel diversity, have comparable LCOE. The EPA concl udes that an evaluation of the LCOE also demonstrates that the c osts of the final standard are reasonable.

a. Calculation of the LCOE

. The LCOE of a power plant source is calculated with the expected lifetime and average capacity factor, and represents the average cost of producing a megawatt-hour (MWh) of electricity over the expected lifetime of the asset

.

http://www.netl.doe.gov/research/energy-analysis/en ergybaseline-studies. 281 http://www.eia.gov/forecasts/aeo/electricity_gener ation.cfm.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 289 of 854 The LCOE incorporates all specified costs, and ther efore is dependent on the project’s capital costs, the fixed and variable operating and maintenance (O&M) costs, the fuel cos ts, the costs to finance the project, and finally on the assumed capacity

factor. 282 The relative contribution of each of these inputs to LCOE will vary among the generating technologies. F or example, the LCOE for a new supercritical PC plant or a new IGCC plant is influenced more by the capital costs (and thus the financing assumptions) and less on fuel costs than a comparab ly sized new NGCC facility which would require less capital inve stment but would be more influenced by assumed fuel costs.

b. Use of the LCOE

. The utility industry and electricity sector regulat ors often use levelized costs as a summary measure for comparing the cost of different potential generating sources. Use of the LCOE as a comparison measure is appropri ate where the facilities being compared would serve load in a sim ilar manner. The value of generation, as reflected in the wholes ale electricity price, can vary seasonally and over the course of a day. Therefore, isolatingIn addition, electricity genera tion technologies differ on dimensions other than just c ost, such as

282 See, e.g. “Cost and Performance Baseline for Fossi l Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015) at p. 17.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 290 of 854 ramping efficiency, intermittency, or uncertainty i n future fuel costs. These other factors are also important in de termining the value of a particular generation technology to a fi rm, and accordingly cost comparisons between two different technologies are most appropriate and insightful when the techno logies align along these other dimensions. Isolating a comparison of technologies based on their costsLCOE is only appropriate when they can be assumed to provide the similar service by essentially providing theservices and similar values of electricity generated. It should be noted that different types of generation do not provide identical services, bu t nevertheless may be similar enough to permit of com parison through use of the LCOE. As we indicated in the proposal, we evaluated publi cly available Integrated Resource Plans ( IRPs ) and other available information (such as public announcements) to deter mine the types of technologies that utilities are considerin g as options for new generating capacity. 283 In the near future, the largest sources of new fossil fuel-fired power generation a re expected to be new NGCC units. But the IRPs also suggested t hat utilities

283 See also discussion at V.C.3 above. The IRPs do not provide an indication of the utility’s intention to pursue a particular generation technology. However, the IRPs do provide an indication of the types of new generating technolog ies that the utility would consider for new generating capacity.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 291 of 854 are interested in a range of technologies that can be used to provide or preserve fuel diversity within the utili ties’*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 292 of 854 respective generating fleets. 284,285 The options for dispatchable generation that can provide intermediate or base-lo ad power and

284 See, e.g. the 2014 IRP of Dominion Virginia Power: With those factors in mind, the 2014 Plan presents two paths forward for resource expansion: a Base Plan, design ed using least-cost planning methods and consistent with the requirements of Rule R8-60 for utility plans to provide "reliabl e electric utility service at least cost over the planning per iod;" and a Fuel Diversity Plan, which includes a broader array of low or zero-emissions options. While the Fuel 2 Diversity Plan currently represents a higher cost option at today' s current and projected commodity prices, its resource mix provid es the important benefits of greater fuel diversity and lo wer carbon intensity. Therefore, the Company will continue rea sonable development of the more diverse and lower carbon in tensive options in the Fuel Diversity Plan and will be read y to implement them as conditions warrant.... The Fuel Div ersity Plan places a greater reliance on generation sources wit h little or no carbon emissions and is less reliant on natural gas. While following the resource expansion scenario in the le ast-cost Base Plan, the Company will continue evaluation and reas onable development efforts for the following projects iden tified in the Fuel Diversity Plan. These include: • Continued development of a third nuclear reactor at North Anna Power Station, using reactor technology supplied by GE-Hitachi Nuclear Energy Americas LLC. While the Company has made no final commitment to building this unit, it recognizes the many operational and environmental benefits of nuclear p ower and continues to actively develop the project. Our cust omers have benefitted from the existing nuclear fleet for many years now, and they will continue to benefit from the existing fleet for many years in the future. A final decision on const ruction of North Anna Unit 3 will not be made until after the Company receives a Combined Operating License or COL from t he U.S. Nuclear Regulatory Commission, now expected in 2016 . The Fuel Diversity Plan includes the addition of North Anna Unit 3's 1,453 megawatts of zero-emissions generation by 202 8. If constructed, the project would provide a dramatic b oost to the regional economy.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 293 of 854 fuel diversity would include new fossil steam units , new nuclear power, and biomass-fired generation.

• Additional reliance on renewable energy, includin g 247 megawatts of onshore wind capacity at sites in west ern Virginia and a 12 megawatt offshore wind demonstration proje ct by 2018. • An additional 559 megawatts of nameplate solar ca pacity, including several new Company-owned photovoltaic CP V) installations. Solar PV costs have declined signifi cantly in recent years, making utility-scale solar much more costeffective than distributed solar, and continuing te chnological development, in which the Company is participating, may allow it to become a more cost-effective source of intermitt ent generation in the future.” cover letter for 2014 IR P - https://www.dom.com/library/domcom/pdfs/corporate/i ntegratedresource-planning/va-irp-2014.pdf.

285 Another example are the recent statements of offic ials of Tri-State Generation and Transmission, available at http://www.wyofile.com/coal-power/, including: “We are considering nuclear, coal and natural gas,” said Ken Anderson, general manager of Tri-State at a confere nce in October [2010], a position that Tri-State represent atives say remains. “We will pick our technology once policy c ertainty comes about,” he added. ...Longer-term forecasts are based on assumptions that may or may not prove well-founded. Because of this uncertainty, Tri-State believes it must retain options for all fuels and technologies. “We will not take anything off the table,” [Tri-Sta te spokesman Lee] Boughey said. That includes coal. “Coal is an affordable and plentiful resource, but it does come with chall enges – and we are looking to different technology that can add ress some of those challenges while continuing to provide a reli able and affordable power supply,” Boughey said. “Some criti cs believe we shouldn’t be looking at resource options that inclu de coal, and even nuclear technology,” Boughey added. “We believ e it would be irresponsible not to consider these fuels or techno logies as part of an affordable, reliable and responsible res ource portfolio.”*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 294 of 854 Thus, in both the proposal and in this final rule, the EPA is comparing the LCOE of technologies that would be reasonably anticipated to be designed, constructed, and operat ed for a similar purpose – that is, to provide dispatchable base load power that provides fuel diversity by relying on a fuel source other than natural gas. In contrast, it may not be appropriate to compare the LCOE for a base load coal-fired plan t with that of a peaking natural gas-fired simple cycle turbine . Similarly, it may not be appropriate to compare LCOE for dispa tchable technologies (i.e., generating sources that can be easily ramped up or down as needed, e.g., coal-fired units, NGCC units, nuclear) with that of non-dispatchable technologies (i.e., generating sources that cannot be reliably ramped u p or down to meet demand, e.g., wind, solar ..)

c. Reasonableness of costs based on LCOE

. An examination of the LCOE of analogous sources of base load, dispatchable power shows that the final stand ard’s LCOE is comparable to that of other sources, as shown in Table 8 below. AsAs mentioned earlier and discussed in further detail below, these estimates rely most heavily on DOE/NETL cost projections for fossil fuel generating technologies and on the updated DOE/ EIA AEO2014AEO 2015 for non-fossil generation technologies

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 295 of 854 Recent estimates from Lazard 286,287 are also provided for nuclear and biomass generation options

. Table 8. Predicted Cost and CO 2 Emission Levels for a Range of Potential New Generation Technologies 288

New Generation Emission LCOE (+30%)* Technology lb CO 2 /MWh-g $/MWh SCPC - no CCS (bit) 1, 700620 77 - 100 76 - 95 SCPC * - – no CCS (low rank) 1, 700740 89 - 116 75 - 94

SCPC + ~16% partial CCS (bit) 1,400 93 - 121 92 - 117

286 Lazard’s Levelized Cost of Energy Analysis – Versi on 8.0; September 2014; available at: http://www.lazard.com/media/1777/levelized_cost_of_ energy_- _version_80.pdf and in the rulemaking docket. 287 Lazard is one of the world's preeminent financial advisory and asset management firms. Lazard’s Global Power, Energy & Infrastructure Group serves private and public sect or clients with advisory services regarding M&A, financing, an d other strategic matters. The group is active in all areas of the traditional and alternative energy industries, incl uding regulated utilities, independent power producers, a dvanced transportation technologies, renewable energy techn ologies, meters, smart grid and energy efficiency technologi es, and infrastructure. http://www.marketwatch.com/story/la zardreleases-new-levelized-cost-of-energy-analysis-2014 -09-18. 288 LCOE cost estimates for SCPC and IGCC cases come f rom “Cost and Performance Baseline for Fossil Energy Plants S upplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants” DOE/NETL-2015/1720 (June 22, 2015). Cost and perfor mance for low rank SCPC is adapted from “Cost and Performance Bas eline for Fossil Energy Plants Volume 3 Executive Summary: Lo w Rank Coal and Natural Gas to Electricity”, DOE/NETL-2010/1399 (September 2011). LCOE cost estimates for nuclear and biomass are derived from “Levelized Cost and Levelized Avoid Cost of Ne w Generation Resources in the Annual Energy Outlook 2015”, June 2015, www.eia.gov/forecasts/aeo/pdf/electricity_generatio n.pdf. LCOE cost estimates for NGCC technology are EPA estimate s based on a range of potential natural gas prices.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 296 of 854

SCPC + ~23% partial CCS (low rank) 1, 100400 110 – 14395 - 121 IGCC - no CCSNuclear (EIA) 1,4500 94 – 122 87 - 115 IGCC + partial CCSNuclear (Lazard) 1,4000 97 - 126 92 - 132 IGCC + partial CCS 1,100 109 – 142 Biomass (EIA) 289

- 94 – 113 NGCCBiomass (Lazard) < 1,000- 87 - 116 52 – 86**

NuclearIGCC 01,430 96 – 125 94 - 120 Biomass

- 103 – 134 290 NGCC Geothermal 01,000 52 – 86** 48 – 62 * Includes the 3 percent CUA * The LCOE ranges presented in Table 8 include an u ncertainty of -15%/+30% on capital costs for SCPC and IGCC cases and an uncertainty of -10%/+30% on capital costs for nucle ar and biomass cases from EIA. This reflects information p rovided by

289 Table 8 includes LCOE figures for biomass-fired ge neration, a potential sources of dispatchable base load power t hat is not fueled by natural gas. The EPA includes this inform ation for completeness, while noting that biomass-fired units in operation in the U.S. are smaller scale and thus are not as r obust analogues as nuclear power. CO 2 emissions are not provided for biomass units because different biomass feedstocks have different net CO 2 emissions; therefore a single emission rate is not appropriate to show in Table 8. 290 Table 8 includes LCOE figures for geothermal and b iomassfired generation, other potential sources of dispat chable base load power that are not fueled by natural gas. The EPA includes this information for completeness, while noting tha t both options have limitations such that they are not as robust analogues as nuclear power. Geothermal generation i s geographically limited and biomass-fired units in o peration in the U.S. are smaller scale.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 297 of 854 EIA. Nuclear staff experts expect that nuclear plan ts currently under construction would not have capital costs und er estimates and that one could expect to see a 30% “upside” var iation in capital cost. There is also insufficient market dat a to get a good statistical range of potential capital cost va riation (i.e. only 2 plants under construction, neither complete) . The nuclear cost estimates from Lazard likewise reflect the ran ge of expected nuclear costs. LCOE estimates displayed in this table for SCPC units with partial CCS as well as for IGCC units use a higher financing cost rate in comparison to the SCP C unit without capture. 291 ** This range represents a natural gas price from $ 5/MMBtu to $10/MMBtu. As shown in Table 8 above , we project that the LCOE for new fossil steam capacity meeting the final 1,400 lb CO 2 /MWh- grossg standard to be substantially similar to that for a new nuclear unit, the principal other alternative to natural ga s to provide new base load power. This is the case for new units firing bituminous and subbituminous coals and dried lignit e. This is another demonstration that the costs of the final s tandard are reasonable because nuclear and fossil steam generat ion each would serve an analogous role in adding dispatchable base load generation diversity – or at least non-NGCC alterna tives

--- to a power provider’s portfolio; hence, they are reasonably viewed as comparable alternatives. 292

291 “Cost and Performance Baseline for Fossil Energy P lants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015) at p. 18. 292 LCOE comparisons of reasonably available complianc e alternatives – IGCC with natural gas co-firing, and SCPC with natural gas co-firing - are found below in Table 9. As shown there, these alternatives are either lower cost tha n SCPC with partial CCS, or of comparable cost.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 298 of 854 As previously mentioned, the DOE/NETL assumed conve ntional financing for cases without CCS and assumed high-ri sk financing for cases with some level of CCS. Specifically a hi gh-risk financial structure resulting in a capital charge f actor (CCF) of 0.124 is used in the study to evaluate the costs of all cases with CO 2 capture (non-capture case uses a conventional fina ncial structure with a CCF of 0.116). 293 As a comparison of how this affects the resulting DOE/NETL costs, a new SCPC ut ilizing 16 percent partial CCS is projected to have an LCOE of $99/MWh (including transportation and storage costs; does n ot include the range for uncertainty). That projected LCOE inc ludes the “high risk financial assumptions”. If the LCOE for that unit were to be calculated using the “conventional finan cing assumptions”, the resulting LCOE would be $94/MWh. This approach is in contrast to that taken by the E IA which applies a 3-percentage-point cost of capital premiu m (the ‘climate uncertainty adder’) to non-capture coal pl ants to reflect the market reaction to potential future GHG regulation. Under current and anticipated market conditions, po wer providers that are considering costs alone in choos ing a fuel source for new intermediate or base load generation will choose

293 “Cost and Performance Baseline for Fossil Energy P lants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015) at p. 7.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 299 of 854 natural gas because of its competitive current and projected price. However , as noted in Section V.H.3 , public IRPs indicate that utilities are considering and selecting techno logies that could provide or preserve fuel diversity within gen erating fleets. For example, utilities have been willing to pay a premium for nuclear power in certain circumstances, as indicated by the recent new constructions of nuclear faciliti es and by IRPs that include new nuclear generation in their p lans. In general, fossil steam and nuclear generation each c an provide dispatchable, base load power while also maintainin g or increasing fuel diversity. 294 Utilities may be willing to pay a premium for these generation sources because they c ould serve as a hedge against the possibility that future natural gas prices will far exceed projected levels. Accordingly, the LCOE analysis demonstrates that the final standard’s costs are in line with power sources that provide analogous services – dispatchable base load power and fuel diversity.

We note further note a number of conservative elements of the costs we used in making this comparison. In par ticular,

294 As another example, San Antonio customers will ben efit from low-carbon power from the Texas Clean Energy Projec t. CPS Energy CEO Doyle Deneby said in a news release: “ Adding clean coal to our portfolio dovetails with our strategy to divers ify and reduce the carbon intensity of the power we supply to our customers .” www.bizjournals.com/sanantonio/news/2014/10/06/c psenergy-strikes-new-deal-to-buy-power-from.html.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 300 of 854 these estimates include the highest value in the pr ojected range of potential costs for partial CCS ,. They do not reflect revenues which can be generated by selling captured CO 2 for enhanced oil recovery, and reflect the costs of par tial CCS rather than potentially less expensive alternative compliance paths such as a utility boiler co-firing with natural gas . See also V.H.7 and 8 below

. 6. Overall Costs and Economic Impacts As noted above, an assessment of national costs is also an appropriate means of evaluating the reasonableness of costs under CAA section 111. See Sierra Club , 657 F.2d at 330. The EPA considered the regulation’s overall costs a nd economic impacts as part of its “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emi ssions for New, Modified, and Reconstructed Stationary Sources : Electric Utility Generating Units” (EPA-452/R-XX-YYY, June 2 015) (RIA).RIA. The RIA demonstrates that these costs would be negligible and that the effects on electricity rate s and other market indicators would similarly be minimal. These results are driven by the existing market con text for fossil-steam generation. Even in the absence of the standards of performance for newly constructed EGUs, substantial new construction of uncontrolled fossil steam units is not anticipated under existing prevailing and anticipat ed future*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 301 of 854 economic conditions. Modeling projections from gove rnment, industry, and academia anticipate that few new foss il steam EGUs will be constructed over the coming decade and that those that are built would have CCS. 295 Instead, EIA data shows that natural gas is likely to be the most widely-used fossil fue l for new construction of electric generating capacity through 2020.in the

near future. 296 Of the coal-fired units moving forward at various advanced stages of construction and development - S outhern Company's Kemper County Energy Facility , and Summit Power's Texas Clean Energy Project (TCEP ), and the Hydrogen Energy California Project (HECA ) – each will deploy IGCC with some

level of CCS. 297 The primary reasons for this rate of current and projected future development of new coal projects i nclude highly competitive natural gas prices, lower electricity d emand, and increases in the supply of renewable energy.

295 RIA chapter 4. For example, even in the EIA’s sensitivity analysis that assumes higher natural gas prices and electricity demand, the EIA does not project any additional coa l beyond its reference case until 2023, in a case where power co mpanies assume no GHGs emission limitations, and until 2024 in a case where power companies do assume GHGs emission limit ations. AEO 2015. 296 Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 2015. 297 These sources received federal assistance under EP Act 2005. However, none of the constraints in that Act affect the discussion in the text above, since that discussion does not relate to technology use or emissions reduction by these sources.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 302 of 854 In its RIA, the EPA considered the overall costs of this regulation in the context of these prevailing marke t trends. Because of the expectation of no new fossil steam g eneration, the RIA projects that this final rule will result i n negligible costs overall on owners and operators of newly cons tructed EGUs by 2022. 298 More broadly, this regulation is not expected to h ave significant effects on fuel markets, electricity pr ices, or the economy as a whole, as described in detail in Chapt er [x]4 of

the RIA. In comparison, courts have upheld past regulations that imposed substantial overall costs in order to prote ct against uncontrolled emissions. As noted above, in Sierra Club v.

Costle , the D.C. Circuit upheld a standard of performance that imposed costly controls on SO 2 emissions from new coal-fired power plants. 657 F.2d at 410. These standards had implications for the economy “at the local and national levels,” as “EPA estimates that utilities will have to spend tens of billions of dollars by 1995 on pollution control under the new NSPS.” Id. at 314. Further, the court acknowledged that “[c]onsum ers will ultimately bear these costs, both directly in the f orm of residential utility bills, and indirectly in the fo rm of higher

298 Conditions in the analysis year of 2022 are repres ented by a model year of 2020.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 303 of 854 consumer prices due to increased energy costs,” bef ore concluding that the costs were reasonable. Id. The projected total incremental capital costs assoc iated with the standard we are finalizing todayin this rule are dramatically lower than was the case for this prior standard, as well as other prior standards summarized previously . For example, when the standard at issue in Sierra Club was upheld, the industry was expected to build, and did build, dozens of plants ultimately meeting the standards – at a proj ected incremental cost of tens of billions of dollars. 299 Here, by contrast, few if any fossil steam EGUs are projecte d to be built in the foreseeable future, indicating that the tota l incremental costs are likely to be considerably more modest. Commenters stated that the cost provision in CAA se ction 111(a)(1) does not authorize the EPA to consider th e nationwide costs of a system of emission reduction in lieu of considering the cost impacts for individual new plants. In this rule, we are considering both sets of costs and, in fact, we are not identifying full CCS as the BSER primarily for reas ons of its cost to individual sources (as we did at proposal). . At the same time, total projected costs are relevant in as sessing the overall reasonableness of costs associated with a s tandard. Our

299 Sierra Club , 657 F

. 2d at 314

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 304 of 854 analysis demonstrates that the impacts on the indus try as a whole are negligible, and are certainly not greater than “what the industry could bear and survive.” 300 These facts support the EPA’s overall conclusion that the costs of the stan dard are

reasonable. However, as noted earlier, for a variety of reasons , some companies may consider coal-fired steam generating units that the modeling does not anticipate. Thus, in Chapter 5 of the RIA, we also present an analysis of the project-level co sts of a newly constructed coal-fired steam generating unit with partial CCS that meets the requirements of this final rule alongside the project-level costs of a newly constructed coal-fir ed unit without CCS. This analysis in RIA chapter 5 indicat es that the quantified benefits of the standards of performance would exceed their costs under a range of assumptions. As required under Executive Order 12866, the EPA co nducts benefit-cost analyses for major Clean Air Act rules , and has done so here. While such analysis can help to infor m policy decisions, as permissible and appropriate under gov erning statutory provisions, the EPA does not use a benefi t-cost test (i.e., a determination of whether monetized benefit s exceed costs) as the sole or primary decision tool when re quired to

300 Portland Cement Ass’n , 513 F. 2d at 508.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 305 of 854 consider costs or to determine whether to issue regulations under the Clean Air Act, and is not doing so here. 301 Nonetheless, as just noted, the RIA analysis shows that the standard of performance has net quantified benefits under a range of assumptions. 7. Opportunities to Further Reduce Compliance Costs While the EPA believes, as detailed above, that the re is sufficient evidence to show that the final standard s of performance for new steam generating units can be m et at a reasonable cost, we also note that there are potent ial opportunities to further reduce compliance costs. W e believe that, in most cases, the actual costs will be less than those presented earlier. As explained in more detail in the following subsec tion, a new utility boiler or IGCC unit can meet the final standard of performance by co-firing with natural gas. Some pro ject developers may choose to utilize natural gas co-fir ing as a means of delaying, rather than avoiding, implementa tion of partial CCS. Developers can also choose to install IGCC with a small amount of natural gas co-firing at costs with in the range of SCPC with partial CCS, although slightly higher.

301 See Memorandum “Consideration of Costs and Benefit s under the Clean Air Act” available in the rulemaking dockets, EPA-HQ-OAR2013-0495 (new sources) and EPA-OAR-HQ-2013-0603.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 306 of 854 The EPA also notes that new units that capture CO 2 will likely be built in areas where there are opportunit ies to sell the captured CO 2 for some useful purpose prior to (or concomitant with) permanent storage. The DOE refers to this as “carbon capture, utilization and storage” or CCUS. In parti cular, the ability to sell captured CO 2 for use in enhanced oil recovery operations offers the most opportunity to reduce co sts. In this regard, the newly-operating Boundary Dam facility i s selling captured CO 2 for EOR. The Kemper facility likewise plans to do

so. 302 In some instances, the costs of CCS may be defrayed by grants or other benefits provided by federal or sta te governments. The need for subsidies to support emer ging energy systems and new control technologies is not unusual . Each of the major types of energy used to generate electricity has been or is currently being supported by some type of govern ment subsidy such as tax benefits, loan guarantees, low-cost lea ses, or direct expenditures for some aspect of development and utilization, ranging from exploration to control in stallation.

302 The EPA is referring to the Kemper facility here a s an example of how costs can be defrayed, not for use o f technology or level of emission reduction achieved. The EPA therefore does not believe that the EPAct05 prevents reference to the fact that Kemper plans to sell captured carbon.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 307 of 854 This is true for fossil fuel-fired ;, as well as nuclear-, geothermal-, wind-, and solar-generated electricity

. As stated earlier, the EPA considers the costs of p artial CCS at a level to meet the final standard of performance t o be reasonable even without considering these opportuni ties to further reduce implementation and compliance costs. We did not in the proposal – and we do not here in this final action – rely on any cost reduction opportunities to justify the costs of meeting the standard as reasonable, but again note the conservative assumptions embodied in our assessment of compliance costs.

a. Cost and feasibility of natural gas co-firing as an alternative compliance pathway

. Although the EPA has determined that implementation of partial CCS at an emission limitation of 1,400 lb C O 2 /MWh- grossg is the BSER for newly constructed fossil fuel-fired steam generating EGUs, we also note that operators can co nsider the use of natural gas co-firing to achieve the final e mission limitation, likely at a lower cost. At the final emissions limitation of 1,400 lb CO 2 /MWh- grg a new supercritical PC or supercritical CFB can meet the standard by co-firing with natural gas at levels up to appro ximately 40 percent (heat input basis) and could potentially av oid (or delay) installation and use of partial CCS altogeth er.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 308 of 854 Most new IGCC units will be able to meet the final standard by capturing less than 10 percent of the CO 2 and many IGCC designs have a sufficient compliance margin such th at they would likely not need to use a water-gas-shift (WGS) reac tor. As an alternative, most new IGCC facilities will be able to meet the final standard by co-firing less than ten percent n atural gas. Natural gas co-firing has long been recognized as a n option for coal-fired boilers to reduce emissions of crite ria and hazardous air pollutants. The EPRI sponsored a study to assess gas co-firing in coal-fired boilers 303 where they examined both technical and economic issues associated with natur al gas cofiring . in coal-fired boilers. 304 They determined that the largest number of applications and the longest expe rience time is with natural gas reburning and with supplemental gas firing. Natural gas reburning has been used primarily as a NO X control technology. It is implemented by introducing natura l gas (up to 20 percent total fuel heat input) in a secondary co mbustion zone (called the “reburn zone”) downstream of the primar y combustion zone in the boiler. Injecting the natural gas creat es a fuel-

303 Gas Cofiring Assessment for Coal Fired Utility Boi lers; Final Report, August 2000; EPRI Technical Report availabl e at www.epri.com. 304 Gas Cofiring Assessment for Coal Fired Utility Boi lers; Final Report, August 2000; EPRI Technical Report availabl e at www.epri.com.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 309 of 854 rich zone where NOxNO X formed in the main combustion zone is reduced to nitrogen and water vapor. Higher levels of natural gas co-firing can be met b y utilizing supplemental gas co-firing (either alone or along with natural gas reburning). This involves the simultane ous firing of natural gas and pulverized coal in a boiler’s prima ry combustion zone. Others have also evaluated configurations tha t would allow coal-fired units to utilize natural gas. 305,306 A 2013 article entitled “Utility Options for Levera ging

Natural Gas” 307 noted that:

Utility owners of coal-fired power stations that wish to balance their exposure to coal-fired generation with additional natural gas–fired generation have several options to consider. The fo ur most practical options are co-firing coal and gas i n the same boiler, converting the coal-fired boiler t o gas-only operation, repowering the coal plant with natural gas–fired combustion turbines, or replacingthe coal plant with a combined cycle plant. [...] Cofiring is the lowest-risk option for substituting g as use for coal.

305 Many of the studies evaluated opportunities to use natural gas reburn, natural gas co-firing and other configu rations in existing coal-fired boilers. Those conclusions woul d also be applicable for new coal-fired boilers. 306 “Dual Fuel Firing – The New Future for the Aging U .S. Based Coal-Fired Boilers”, presented by Riley Power, Inc. at 37th International Technical Conference on Clean Coal an d Fuel Systems June 2012 Clearwater, FL, available at http://www.babcockpower.com/pdf/RPI-TP-0228.pdf. 307 Utility Options for Leveraging Natural Gas, 10/01/ 2013 article in Power . Available at http://www.powermag.com/utilityoptions-for-leveraging-natural-gas //.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 310 of 854 The EPA examined compliance costs for a new steam generating unit to meet the final standard of perfo rmance using natural gas co-firing and compared those costs to t he estimated costs of meeting the final standards using partial CCS. Those costs are provided below in Table 9. Table 9. Predicted Costs to Meet the Final Standard Using Natural Gas Co-firing. 308 New Generation Emission LCOE * (+30%) Technology lb CO 2 /MWh-g $/MWh $/MWh SCPC - no CCS 1, 700620 7782 100 SCPC + ~16% partial CCS 1,400 9399 121 SCPC + ~34% NG co-fire 1,400 9092 - IGCC - no CCS 1, 450434 94103 122 IGCC + partial CCS 1,400 97 126 IGCC + ~6% NG co-fire 1,400 95105 -

NGCC * < 1,000 59 – 8660

- * The LCOE values for non-natural gas generation (i.e., SCPC with and without CCS) include +30% for uncertainty. Thecost using NG technologies (i.e., co- firingfire and NGCC ) are costs assuming assume a rangenatural gas price of natural gas prices from $6. 1119 /mmBtu to $10.00/mmBtu..

The EPA thus again notes that the cost assumptions it is making herein its BSER determination are highly conservative. That is, by costing partial CCS as BSER, the EPA is likelymay be

308 Costs and emissions for cases that do not utilize natural gas co-firing are from “Cost and Performance Baseline f or Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015). Costs and emissions for natural gas co-fired cases are EP A estimates. Deleted Cells

Deleted Cells

Deleted Cells*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 311 of 854 overestimating actual compliance costs since there exist other less expensive means of meeting the promulgated sta ndard. 309 Notwithstanding that costs for a SCPC to meet the s tandard would be lower if it co-fired with natural gas, we have not identified that compliance alternative as BSER beca use we believe that new coal-fired steam electric generati ng capacity would be built to provide fuel diversity, and burni ng substantial amounts of natural gas would be contrar y to that objective. In addition, this choice would not promo te use of advanced pollution control technology. New IGCC has costs which are comparable to SCPC, as does IGCC with natural g as cofiring, 310 but we are choosing not to identify it as BSER for reasons stated at Sections V.C.2 and V.P: use of IG CC does not advance emission control beyond current levels of p erformance for sources which may choose to utilize IGCC techno logy. Nonetheless, use of IGCC remains a viable, demonstr ated compliance option to meet the 1,400 lb CO 2 /MWh-g standard of

309 Certain commenters argued that the proposed standa rd essentially mandated a sole method of compliance, a nd hence constituted a work practice for purposes of section 111(h) of the Act. These commenters argued further that the E PA had failed to justify the proposal under the section 111(h) cr iteria. The EPA disagrees with the premise of these comments, b ut, in any case, there are clearly multiple compliance paths a vailable for achieving the final standard. 310 IGCC units already have combined cycle capacity, a nd so can be readily operated in whole or in part using natur al gas as a fuel. Indeed, both the Edwardsport and Kemper IGCC facilities have operated at times by firing exclusively natura l gas.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 312 of 854 performance, and is available at reasonable cost an d (as shown at Section V.P below) without significant adverse n on-air quality impacts or energy implications.

b. Costs are reasonably expected to decrease over time

. The EPA reasonably expects that the costs of CCS wi ll decrease over time as the technology becomes more w idely deployed. Although, for the reasons that have been noted, we consider the current costs of CCS to be reasonable, the projected decrease in those costs further supports their reasonableness. The D.C. Circuit case law that auth orizes determining the “best” available technology on the basis of reasonable future projections supports taking into account projected cost reductions as a way to support the r easonableness

of the costs. We expect the costs of CCS technologies to decrease for several reasons. We expect that significant additio nal knowledge will be gained from deployment and operation of the new coalfired generation facilities that are either operati ng or are nearing completion. These would include the Boundar y Dam Unit #3 facility, the Petra Nova WA Parish project, and the Kemper County IGCC facility. The operators of the Boundary Dam Unit #3 are considering construction of additional CCS unit s and have projected that the next units could be constructed at a cost of*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 313 of 854 at least 30 percent less than that at Unit #3. 311 These savings primarily come from application of lessons learned from the Unit #3 design and construction. To facilitate the transfer of the technology and to accelerate development of carbon capture technology , SaskPower has created the CCS Global Consortium. 312 This consortium provides SaskPower the opportunity to share the kno wledge and experience from the Boundary Dam Unit #3 facility w ith global energy leaders, technology developers, and project developers. SaskPower, in partnership with Mitsubishi and Hitac hi, is also helping to advance CCS knowledge and technology dev elopment through the creation of the Shand Carbon Capture Te st Facility (CCTF). 313 The test facility will provide technology develope rs with an opportunity to test new and emerging carbon capture systems for controlling carbon emissions from coal- fired power plants. The DOE also sponsors testing at the National Carbo n Capture Center (NCCC). The NCCC – located at Southe rn Company’s Plant Gaston in Wilsonville, AL – provides first-cl ass

311 “Boundary Dam – The Future is Here”, plenary prese ntation by Mike Monea at the 12 th International Conference on Greenhouse Gas Technologies (GHGT-12), Austin, TX (October 2014). 312 http://www.saskpowerccs.com/consortium //. 313 http:// www.saskpowerccs.com/ccs-projects/shand-carboncapture-test-facility //.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 314 of 854 facilities to test new capture technologies for ext ended periods under commercially representative conditions with c oal-derived flue gas and syngas. 314 We expect continued additional cost reductions to c ome from knowledge gained from continued operation of non-po wer sector industrial projects which, as we have discussed, ar e informative in transferring the technology to power sector appl ications. We expect the on-going research and development effort s – such as those sponsored by the DOE/NETL. Significant reductions in the cost of CO 2 capture would be consistent with overall experience with the cost of pollution control technology. Reductions in the cost of air p ollution control technologies as a result of learning-by-doi ng, reductions in financial premiums related to risk, r esearch and development investments, and other factors have bee n observed

over the decades.

c. Opportunities to reduce cost through sales of captu red CO 2 . Geologic storage options include use of CO 2 in EOR operations, which is the injection of fluids into a reservoir after production yields have decreased from primary production in order to increase oil production efficiency. CO 2 -EOR has been successfully used for decades at many production fi elds

314 www.nationalcarboncapturecenter.com/index.html.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 315 of 854 throughout the U.S. to increase oil recovery. The u se of CO 2 for EOR can significantly lower the net cost of impleme nting CCS. The opportunity to sell the captured CO 2 for EOR, rather than paying directly for its long-term storage, improves the overall economics of the new generating unit. According to the International Energy Agency (IEA), of the CCS proje cts under construction or at an advanced stage of planning, 7 0 percent intend to use captured CO 2 to improve recovery of oil in mature fields. 315 See also Section V.M.3 below. I. Key Comments Regarding the EPA’s Consideration of Costs In its consideration of the costs associated with t he final standard, the EPA considered a range of different c ost metrics, each with its individual strengths and weaknesses. As discussed above, each metric supports the EPA’s conclusion th at the costs of the final standard are reasonable. In this section, we review the comments received on assessing cost reasonableness and specific cost met rics. We explain how these comments informed our considerati on of different metrics and cost reasonableness in genera l.

315 Tracking Clean Energy Progress 2013, International Energy Agency (IEA), Input to the Clean Energy Ministerial , OECD/IEA 2013.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 316 of 854 1. Use of LCOE as a Cost Metric As noted, CAA section 111(a) directs the EPA to consider “cost” in determining if the BSER is adequately dem onstrated. It does not provide further guidance as to how costs a re to be considered, thus affording the EPA considerable dis cretion to choose a reasonable means of cost consideration. Se e, e.g. Lignite Energy Council v. EPA , 198 F. 3d at 933. Certain commenters nonetheless argued that LCOE was an impe rmissible metric because it does not measure the cost of achi eving the emission reduction, but rather measures the impact on the product produced by the entity subject to the stand ard. 316 The EPA does not agree that its authority is so limited . Indeed, in the first decided case under section 111, the D.C. Circuit, in holding that the EPA’s consideration of costs was r easonable, specifically noted the EPA’s examination of the imp act of the standards on the regulated source category’s produc t in comparison to competitive products. Portland Cement Ass’n v.

EPA , 486 F. 2d at 388 (“costs of control equipment cou ld be passed on without substantially affecting competiti on with construction substitutes such as steel, asphalt, an d aluminum”). Commenters also argued that the choice of LCOE as a cost metric masked consideration of the considerable cap ital costs

316 Comments of EEI, pp 94-5.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 317 of 854 associated with CCS. The EPA disagrees with this co ntention. The LCOE does not mask consideration of capital costs. Rather, as explained at V.H.5 above, it addresses all costs equallyLCOE is a summary metric that expresses the full cost (e.g. , capital, O&M, fuel) of generating electricity and therefore provides a useful summary metric of all sources of costs per unit of production (i.e., megawatt-hours). Provided that th ose megawatthours are equally valuableprovide similar electricity ser vices and align on dimensions other than just cost , then the LCOE provides a useful comparison of which technologies are least

cost. The EPA certainly does not minimize that project de velopers must take capital costs into consideration, and accordingly as discussed in Section V.H.4 above, the EPA accordingly has considered direct capital costs here as part of its assessment and found those costs to be reasonable. AtIn addition, the same time, the agency believes LCOE is a valuable comple mentary metric because there are other costsEPA notes that are also considered when evaluating technology options to pr ovide new generating capacity. its comparison of the marginal impacts from an individual illustrative facility’s compliance wi th the standard, discussed in detail above and in the RIA Chapter 5, took into account the marginal capital costs that w ould be incurred by an individual facility.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 318 of 854 According to EIA 317 , the capital costs represent roughlyapproximately 63 percent of the LCOE for a new coal-fired SCPC plant; roughlyapproximately 66 percent of the LCOE for a new IGCC plant; roughlyapproximately 74 percent of the LCOE for a new nuclear plant; and only about 22 percent of t he LCOE for a new NGCC unit. The LCOE of a new NGCC unit is much more strongly affected by fuel costs (natural gas). As we have di scussed in detail in this preamble, in the preamble for the Ja nuary 2014 proposal, and in associated technical support docum ents, for a variety of reasons, the power sector has moved toward increased use of natural gas for a variety of reasons . If capital was the only cost that utilities and project developers con sidered, then they would almost certainly always choose to build a new NGCC unit. However, the EPA recognizes the a variety of factors that can be involved in selecting a generation source be yond capital

costs , and. Accordingly, in considering cost reasonableness we accordingly alsothe EPA considered metrics that encompassed

other costs as well as the value of fuel and fleet diversity. Some commenters maintained that even if LCOE was a proper cost metric, the comparison with the costs of a new nuclear power plant is improper because nuclear itself is a highly expensive technology. The EPA disagrees. The compar ison is

317 http://www.eia.gov/forecasts/aeo/electricity_gener ation.cfm

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 319 of 854 appropriate and valid because, as discussed at V.H.3 above, under current and foreseeable economic conditions a ffecting the cost of new fossil steam generation and new nuclear generation relative to the cost of new natural gas generation, bothneither new nuclear power andnor fossil steam generation are similarly

not competitive with new natural gas if evaluated on t he basis of LCOE alone. Nonetheless, both are important pote ntial alternatives to natural gas power for those interes ted in dispatchable base load power that maintains or incr eases fuel diversity. As shown in a survey of recent IRP filings in the

docket 318 and Section II.C.5 above, several utilities are considering new nuclear power as a potential genera tion option. Because both fossil steam and nuclear generation se rve a comparable role of offering a diverse source of bas e load power generation, the EPA concludes that the comparison of their LCOE is a valid approach to evaluating cost reasonablene ss. Finally, the EPA noted that new nuclear addresses p otential risks (including future costs to the source) associ ated with future carbon liabilities – the same risks coal wit h some degree of CCS would address. See 79 FR at 1477.

318 Technical Support Document - “Review of Electric U tility Integrated Resource Plans” (May 2015), available in the rulemaking docket EPA-HQ-OAR-2013-0495.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 320 of 854 2. Use of Cost Estimates from DOE/NETL and DOE/EIA In the January 2014 proposal, the EPA relied mostly on the cost projections for new fossil fuel-fired generati ng sources that were informed by cost studies conducted by DOE /NETL. The EPA relied on the EIA’s AEO2013AEO 2013 projections for nonfossil based generating sources (i.e., nuclear, ren ewables, etc.). For this final rule, the EPA continues to re ly most heavily on DOE/NETL cost projections for fossil fue l generating technologies and on the updated DOE/EIA AEO2014AEO 2014 for

nuclear and other baseloadbase load non-fossil generation technologies.

a. DOE/NETL cost and performance studies

. The DOE/NETL “Cost and Performance Baselines for Fo ssil Energy Plants” are a series of studies conducted by NETL to establish estimates for the cost and performance of combustion and gasification based power plants with and withou t CO 2 capture and storage. 319 The studies evaluate numerous technology configurations utilizing different coal ranks and n atural gas. The EPA relied on those sources because the NETL st udies are the most comprehensive and transparent of the a vailable cost studies and NETL has a reputation in the power sect or industry

319 http://www.netl.doe.gov/research/energy-analysis/e nergybaseline-studies

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 321 of 854 for producing high quality, reliable work. 320 The NETL studies were extensively peer reviewed. 321 The EPA Science Advisory Board Work Group considering the adequacy of the peer rev iew noted the EPA staff’s statement that “the NETL studies were a ll peer reviewed under DOE peer review protocols”, further noted the EPA staff’s statement that “the different levels of rev iew of these DOE documents met the requirements to support the a nalyses as defined by the EPA Peer Review Handbook,” and concl uded that “peer review on the DOE documents” was conducted “a t a level required (sic) by agency guidance.” 322 The cost estimates were indicated by DOE/NETL to ca rry an accuracy of -15 percent to +30 percent on the capital costs , consistent with a AACE Class 4 cost estimate – i.e ,., a

320 The NETL costs and studies are often cited in acad emic and other publications. 321 The initial NETL study “Cost and Performance Basel ine for Fossil Energy Plants, Vol. 1: Bituminous Coal and N atural Gas to Electricity” (2006) was subject to peer review by i ndustry experts, academia, and government research and regu latory agencies. Subsequent iterations of the study were n ot further peer reviewed because the modeling procedures used in the cost estimation were not revised. 322 Letter from James Mihelcic, Chair, SAB Work Group on EPA Planned Actions for SAB Consideration of the Underl ying Science to Members of the Chartered SAB and SAB Liaisons (p age 3, Jan. 24, 2014). http://yosemite.epa.gov/sab/sabproduct.nsf/F43D8907 0E89893485257 C5A007AF573/$File/SAB+work+grp+memo+w+attach+201401 07.pdf

. The SAB’s statement that these guidance documents “ require” any specific peer review is an overstatement, since gui dance documents, by definition, do not mandate any specif ic course of action.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 322 of 854 “feasibility study” level of design engineering. 323 The DOE/NETL further notes that “The value of the study lies not in the absolute accuracy of the individual case results bu t in the fact

that all cases were evaluated under the same set of technical and economic assumptions. This consistency of appro ach allows meaningful comparisons among the cases evaluated.” 324 For the final standard, the EPA made particular use of the most recent NETL cost estimates for post-combustion CCS, which reflect up-to-date vendor quotes and incorporate th e postcombustion capture technology – the Shell Cansolv a mine-based process – that is being utilized at the Boundary Da m Unit #3 facility. 325 The EPA used this latest version of the NETL studi es not only to assure that it considers the most up-to -date information but also to address public comments cri ticizing the proposal for relying on out-of-date cost informatio n. b. Other studies that corroborate NETL cost estimates

. A variety of government, industry and academic grou ps routinely conduct studies to estimate costs of new generating

323 Recommended Practice 18R-97 of the Association for the Advancement of Cost Engineering International (AACE ) describes a Cost Estimate Classification System as applied in E ngineering, Procurement and Construction for the process indust ries. 324 “Cost and Performance Baseline for Fossil Energy P lants Volume 1: Bituminous Coal and Natural Gas to Electr icity” Rev 2a (Sept 2013); DOE/NETL-2010/1397, page 9. 325 Cost and Performance Baseline for Fossil Energy Pl ants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electri city, Revision 3, July 6, 2015, DOE/NETL-2015/1723.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 323 of 854 technologies. These studies use techno-economic mod els to predict the cost to build a new generating facility at some point in the future. These studies often use leveli zed cost of electricity (LCOE) to summarize costs and to compar e the competiveness of the different generating technolog ies. A variety of groups have recently published LCOE es timates for new dispatchable generating technologies. Those are shown below in Table 10. The table shows LCOE projections from the EPA’s January 2014 proposal, from studies conducted by the Electric Power Research Institute (EPRI) 326 , by the DOE’s Energy Information Administration (EIA) in their 20142015 Annual Energy Outlook ( AEO2014AEO 2015 ), by the DOE’s National Energy Technology Laboratory (NETL), and by researchers fr om the Department of Engineering and Public Policy at the Carnegie Mellon University (CMU) in Pittsburgh, PA.

326 EPRI is a non-profit organization, headquartered i n Palo Alto, CA, that conducts research on issues related to the U.S. electric power industry (www.epri.com).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review ***

Formatted: Normal The Global CCS Institute 327 has recently published a report that examines costs of major low and zero emissions technologies currently available for power generation and compar es the predicted LCOEs of those technologies. Importantly, the analysis presented in the report uses cost and performance d ata from several recent studies, and applies a common method ology and economic parameters to derive comparable lifetime c osts. Analysis and findings in the paper reflect costs sp ecific to the

U.S. The fact that these various groups have conducted independent studies and that the results of those i ndependent studies are reasonably consistent with the estimate s of DOE/NETL are further indications that the DOE/NETL cost esti mates are reasonable.

327 www.globalccsinstitute.com.*** EO 12866 Review - Draft – Do Not Cite, Quote orRelease During Review ***Formatted:NormalTable 10. Selection of Levelized Cost of Electricity (LCOE) ProjectionsNew GenerationEPAProposalLazard328EPRI329AEO2014AEO2015330DOE/NETL331CMU332GCCSI333**32879 FR 1430; Tables 6 and 7; Partial CCC is an emission limitation of 1,100 lb CO2/MWh.Lazard’s Levelized Cost of Energy Analysis – Version 8.0 (Sept 2014); available athttp://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf and in therulemaking docket.329"Program on Technology Innovation: Integrated Generation Technology Options 2012;Report 1026656; Available at:www.epri.com.330“Levelized Cost and Levelized Avoided Cost of NewGeneration Resources in the AnnualEnergy Outlook20142015”, Available at:www.eia.gov/forecasts/aeo/electricity_generation.cfm; the LCOE values displayedincorporate -10%/+30% for uncertainty for biomass and nuclear.331Recommendation by NETL for next-of-a-kind cost projections. Available in therulemaking docket at EPA-HQ-OAR-2013-0495-0065. Range includes +30 percent uncertainty.“Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2Capture Rate in Coal-Fired Power Plants” DOE/NETL-2015/1720 (June 22, 2015).332CMU is Carnegie Mellon University; Zhai, H., Rubin, E.; “Comparative Performance andCost Assessments of Coal- and Natural Gas-Fired Power Plants under a CO2EmissionPerformance Standard Regulation”,Energy & Fuels, 2013, 27, 4290, Table 1; Note: theauthors assumed an emission limit of 1,000 lb CO2/MWh.333“The Costs of CCS and other Low-Carbon Technologies - 2015 update” July 2015, GlobalCCS Institute, Available at:http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs-ccsother-low-carbon-technologies-2015-update.pdf.Inserted Cells***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review ***Page326of854Technology$20112014/MWh$2011/MWh$20122013/MWh*$2011/MWh*$2010/MWh$2014/MWhSCPC– no CCS92*6662-–7787 - 114*9591 -11876 –955978SCPC( -full CCS)147151102 –137-147 -191140 –176-115 -160SCPC(partial -16%CCS**)110-- -110 -12692 -11780--Nuclear***92 – 13285 – 9787 – 115--86 - 102Biomass87 – 11690 – 15594 – 113--123 -137IGCC9710282 – 96106 - 132*116101 -13194 –120--IGCC( -full CCS)136171105 –136137 - 163144142-185– 178--IGCC(partialCCS**)109--112 - 146-NGCC59 - 8661 – 8733 – 6559 - 867360 - 77586360Nuclear103 - 11485 – 9793 - 102--Geothermal80 - 9984 - 12946 - 50--Biomass97 - 13090 - 15592 - 123--* These* EIA, incost projectionsinclude for SCPC and IGCC with no CCS, includesa climateuncertainty adder (CUA);),which is a 3-percentage point increase in the costof capital.Inserted CellsInserted Cells***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review ***Page327of854In contrast, DOE/NETL utilized conventional financing for cases without CCS and utilizedhigh-risk financial assumptions for cases that include CCS.** Partial CCS is 1,100 lb/MWh for EPA costs; 1,000lb/MWh for CMU cost*** EO 12866 Review - Draft – Do Not Cite, Quote orRelease During Review ***** The Global CCS Institute provided range for coalwith full CCS (shown as “CCS(coal)”in Figure 5.2 of the referenced report) reflects acombination of costs for both PC andIGCC coal plants.*** EIA AEO assumes use of Westinghouse AP1000 technology. Other groups assume a widerrange of technology options.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review ***

The LCOE values from the Lazard, EPRI , EIA , and NETL studies are presented as a range. The EPRI costs incorporate uncertainty reflecting the r ange of inputs (i.e., capital costs, fuel costs, fi xed and variable O&M, etc.). The NETL costs are indicated t o carry an accuracy of -15 percent to + 30 percent, consistent with a “feasibility study” level of desi gn. The range in Table 10 is the NETL projected cos ts with the + -15 percent to + 30 percent uncertainty added as on the higher estimate in the range. The range presented for the EIA AEO2014 LCOE values is intended to represent regional variation for new ge nerating sources (reflecting regional differences in constru ction labor costs, capital costs , and resource availability).. Overall, as can be seen from the results in Table 10, the range of LCOE estimates from the different groups are in reasonab le agreement with the DOE/NETL estimates most often representing the most conservative of the estimates shown

. The EIA cost estimates include a climate uncertaint y adder (CUA) – represented by a three percent increase to the weighted average cost of capital — to certain coal-fired cap acity types. The EIA developed the CUA to address inconsistencie s between power sector modeling absent GHG regulation and the widespread

use of a cost of CO 2 emissions in power sector resource planning. The CUA reflects the additional planning cost typic ally assigned by project developers and utilities to GHG-intensiv e projects in a context of climate uncertainty. The EPA believes the CUA is consistent with the industry’s planning and evaluat ion framework Formatted: Font: +Body (Calibri), 11 pt*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 330 of 854 (demonstrable through IRPs and PUC orders) and is t herefore pertinent when evaluating the cost competitiveness of alternative generating technologies. The EPA believ es the CUA is relevant in considering the range of costs that pow er companies are willing to pay for generation alternatives to n atural gas and includes the CUA in the cost of coal-fired util ity boilers when evaluating competitiveness of that generating technology

.

c. Industry information that corroborates NETL cost es timates

. Information from vendors of CCS technology also sup ports the reliability of the cost estimates the EPA is using here. 334 Specifically, the EPA had conversations with repres entatives from Summit Carbon Capture, LLC regarding available cost information. Cost estimates provided by another lea ding provider of CCS technology likewise are consistent (indeed, somewhat less than) the estimates the EPA is using for purposes of cost analysis in the rule. Summit Carbon Capture’s primary business is large-s cale carbon capture from power and other industrial proj ects and use of the captured CO 2 for EOR. 335 Summit is actively working with several different technology companies offering CO 2 capture

334 See Section V.F above, explaining that the D.C. Circuit has repeatedly stated that vendor statements are probat ive in demonstrating that a technology is adequately demon strated under section 111. 335 http://www.summitpower.com/projects/carbon-capture //.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 331 of 854 systems, including the leading equipment manufactur ers for fossil fuel power production equipment. Their curre nt projects include the 400 MW IGCC Texas Clean Energy Project and the Caledonia Clean Energy Project – a new project unde rway in the United Kingdom – and a variety of other projects un der development which are not yet public. Summit is also interested in potentially retrofitti ng CCS onto existing coal-fired plants for the purpose of capturing CO 2 for sale to EOR markets. Summit provided the EPA wi th copies of slides from a presentation that it has used in diff erent public

forums. 336 The presentation focused on costs to retrofit available carbon capture equipment at an existing P C power plant that is ideally located to take advantage of opport unities to sell captured CO 2 for use in EOR operations. Summit received proprietary costing information from numerous techn ology providers and that information, along with other pu blically available information, was used to develop their co st predictions. 337 Though the primary focus of their effort was to

336 “Coal’s Role in a Low Carbon Energy Environment”, presented at 2015 Euromoney Power & Renewables Conference, re marks by Jeffrey Brown (amended to address EPA questions on the original). Available in the rulemaking docket (ID: EPA-HQ-OAR2013-0495).. 337 No proprietary or business confidential informatio n was shared with the EPA. No specific vendors were mentioned by name during discussions with Summit Power. Summit also u sed available DOE/NETL and EIA cost information.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 332 of 854 examine costs associated with retrofitting CCS to a n existing coal fired power plant, Summit Power also calculate d costs for several new generation scenarios – including the co st of a new NGCC, a new SCPC, a new SCPC with full CCS, and a n ew SCPC with partial CCS at 50 percent. The costs are reasonably consistent with costs in those predicted by NETL, EIA, EPRI and others. The company ultimately concluded that “in a world of un certain gas prices, falling CO 2 capture equipment prices, improving CCS process efficiency, and possible compliance costs ... existing coal plants retrofitted with available CCS equipmen t can be cost competitive with development of new NGCC generation .” 338 In June 2012, Alstom Power released a report entitl ed “Cost assessment of fossil power plants equipped with CCS under typical scenarios”. 339, The study examined costs for a new coalfired power plant implementing post-combustion CCS (full CCS) in Europe, in North America, and in Asia. The results for the North

338 Others have come to similar conclusions – that ret rofit of CCS technology at existing coal-fired power plants can be feasible – e.g., “The results indicate that for abo ut 60 gigawatts of the existing coal-fired capacity, the implementation of partial CO 2 capture appears feasible, though its cost is highly dependent on the unit characteri stics and fuel prices.” (Zhai, H.; Ou, Y.; Rubin, E.S.; “Oppo rtunities for Decarbonizing Existing U.S. Coal-fired Plants via C O 2 Capture, Utilization, and Storage”, accepted for publication in Env. Sci & Tech. (2015). 339 Leandri, J., Skea, A., Bohtz, C., Heinz, G.; “Cost assessment of fossil power plants equipped with CCS under typi cal scenarios”, Alstom Power, June 2012. Available in t he rulemaking docket: EPA-HQ-OAR-2013-0495.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 333 of 854 American case – along with similar cost estimates f rom the Summit – are shown in Table 11 below. The EPADOE/NETL estimated costs are also included for comparison. The results show predicted costs for a new SCPC ranging from $53/MWh to $ 8182 /MWh and costs to implement full CCS ranging from $97/MW h to $ 147143 /MWh. Costs to implement varying levels of partial CCS are also provided for comparison. The industry cost estimates are on the lower end of the range of costs predicte d from other techno-economic studies (see Table 11 below) and, l ike those economic studies, are affected by the specific assu mptions. There is veryAs with the techo-economic studies pre sented earlier in Table, there is relatively good agreement among the studies these projected costs and the DOE/NETL cost s. There is relatively good agreement in the incremental levelized cost to implement full CCS on the new SCPC units (ranging f rom 8274 to 85 percent ).) and to implement 50 percent CCS on the new SCPC unit (from 41 to 45 percent increase). These indust ry estimates are also lower than the DOE/NETL estimates for both full and 50 percent partial CCS (with the incremental cost perc entage for full CCS being almost identical), providing further support for the reasonableness of the EPA using the NETL cost e stimates

here.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 334 of 854 Table 11. Industry LCOE Estimates for Implementatio n of PostCombustion CCS 340 Summit Alstom EPADOE/NETL $/MWh $/MWh* $/MWh SCPC 64.5 52.6 81.082.3 SCPC + full CCS 117.6 97.4 147.0152.4 Full CCS incremental cost, % 82.3% 85.0% 81.585.2 % SCPC + 50% CCS 91.1 - -123.6 50% CCS incremental cost, % 41.2% - 50.1% SCPC + 4035 % CCS - - 110.0114.7 SCPC + 2016 % CCS - - 97.0100.5 NGCC** 47.7 35.0 5952 .0 ** * Costs are from Figure 2 in the referenced Alstom report (North American case); costs are presented as €/MWh in the report. The costs were converted to $/MWh assuming a conversion rate of 1 USD = 0.76 € (in 2012). **** NGCC cost is estimated by the EPA using NETL i nformation. Assumed natural gas prices = Summit ($4/mmBtu); Ast om ($3.9/mmBtu); EPA ($ 6.115.00/mmBtu ).

The EPA notes that in its public comments, Alstom maintained that “no CCS projects that would [sic] b e considered cost competitive in today’s energy economy.” 341 As explained

340 Note that in other tables in this preamble, the EP A has presented LCOE values from the DOE/NETL work as a r ange in order to incorporate the uncertainty on the capital costs . The range is not present here for easy comparison with the in dustry costs which were not provided as a range. The full range of DOE/NETL costs for each of the cases presented can be found in Exhibit A3 in “Cost and Performance Baseline for Fossil Ener gy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015), p. 18.

341 Alstom Comment p. 3. The comment also urged the EPA to evaluate costs without considering EOR opportunitie s (which in fact is our methodology, albeit a conservative one) , and without considering possible subsidies. Id. The LCOE and ca pital cost estimates above are direct cost comparisons, again consistent with the commenter’s position.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 335 of 854 above, no steam electric EGU would be cost competit ive even without CCS – and that is substantiated in the proj ected costs presentpresented above in Table 11 where NGCC is consistently the most economic new generation option when compar ed to the other listed technologies. Alstom does not explain (or address) why the cost premium for partial CCS would be a dec isive deterrent for capacity that would otherwise be cons tructed. More important, Alstom does not challenge the specific c ost estimates used by the EPA at proposal (and in this final rule),, nor disavow its own estimates of CCS costs (which are e ven less) which it is publically disseminating in the marketp lace. See also Section V.F. 3 above, quoting Alstom’s press release stating unequivocally that “CCS works and is cost-e ffective”. The EPA reasonably is relying on the specific Alsto m estimates which it is using for its own commercial purposes, and not on the generalized concerns presented in its public co mments. d. Use of cost information from EIA Annual Energy Outl ook (AEO ). ) For the January 2014 proposal the EPA chose to rely on the

EIA AEO2013AEO 2013 cost projections for non-fossil based generation. The AEO presents long-term annual proje ctions of energy supply, demand, and prices focused on U.S. e nergy markets. The predictions are based on results from EIA’s National Energy Modeling System (NEMS). The AEO cos ts are*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 336 of 854 updated annually, they are highly scrutinized, and they are widely used by those involved in the energy sector. In the January 2014 proposal, the EPA presented LCO E costs for new non-fossil dispatchable generation (see 77 FR 1477, Table 7) from the AEO2013. Those costs were updated as part of the AEO2014 release. The changes are shown below in Table 12 belowAEO 2013. Those costs were updated as part of the AEO 2015 release. The estimated cost for all of these techno logies decreased from AEO 2013 to AEO 2014 and AEO 2015. T his was due to changes in the interest rates that resulted in l ower financing costs relative to those used the AEO 2013

. 342 The EIA commissioned a comprehensive update of its capital cost assumptions for all generation technologies in 2013 . Fuel cost and financial assumptions are updated for each edit ion of the Annual Energy Outlook

. Table 12. Predicted Cost and Regional Variation (Ra nge) for New Non-fossil Dispatchable Generating Technologies AEO2013 AEO2013 AEO2014 AEO2014 average range* average range* Technology $2011/MWh $2011/MWh $2012/MWh $2012/MWh

Nuclear 108 104-115 96 93-102 Nuclear (w/subsidy)

- - 86 83

- 92 Biomass 111 98-131 103 92-123 Geothermal 90 81-100 48 46-50

342 www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantc osts.pdf.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 337 of 854 * Note that the “range” is intended to account for the significant regional variation in LCOE values based on local labor markets and the cost and availability of fuel or energy resources. The estimated cost for all of these technologies de creased from AEO2013 to AEO2014. This was due to changes in the macroeconomic projections that resulted in lower fi nancing costs in AEO2014 relative to the AEO2013. The EIA did not make any major updates to the initial cost inputs for most t echnologies, including nuclear.

e. Accounting for uncertainty of projected costs

. As previously mentioned, the projected costs are de pendent upon a range of assumptions including the projected capital costs, the cost of financing the project, the fixed and variable O&M costs, the projected fuel costs, and incorporat ion of any incentives such as tax credits or favorable financi ng that may be available to the project developer. There are al so regional or geographic differences that affect the final cos t of a project. The LCOE projections in this final action are not intended to provide an absolute cost for a new proj ect using any of these respective technologies. Large constructio n projects – as these would be – would be subjected to detailed cost analyses that would take into consideration site-specific in formation and specific design details in order to determine the p roject costs.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 338 of 854 The DOE/NETL noted that the cost estimates from the ir studies carry an accuracy in the range of -15 perce nt to +30 percent, which is consistent with a “feasibility st udy” level of design. They also noted that the value of the studi es lies “not in the absolute accuracy of the individual case res ults but in

the fact that all cases were evaluated under the sa me set of technical and economic assumptions. This consistenc y of approach allows meaningful comparisons among the cases evalu ated.”

The EIA AEO2014AEO 2015 presented LCOE costs as a single point estimate representing average nationwide cost s and separately as a range to represent the regional var iation in

costs. That range reflecting regional variation is present ed in Table 12. In order to compare the fossil fuel generation technologies from the NETL studies with the cost pr ojections for non-fossil dispatchable technologies from EIA AEO2014AEO 2015 , we assume that the EIA studies would carry a simila r level of uncertainty (i.e., +30 percent) and we present the AEO2014 projected costs as the average nationwide LCOE plus an additional 30 percent to account for uncertainty.+3 0 percent) and we present the AEO 2015 projected costs as the average nationwide LCOE with a range of -10 percent to +30 percent to*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 339 of 854 account for uncertainty. 343 The EIA does not provide uncertainty estimates in the AEO cost projections. However, nuc lear experts from EIA staff have indicated to the EPA that a ran ge of uncertainty of -10 percent to +30 percent on the ca pital component of the LCOE can be expected based on mark et uncertainties. Specifically, these staff experts ex pect that nuclear plants currently under construction would n ot have capital costs under estimates and that one could ex pect to see a 30 percent “upside” variation in capital cost. Ther e is also insufficient market data to get a good statistical range of potential capital cost variation (i.e., only two pl ants under construction, neither complete). This is reasonably consistent with estimates for nuclear costs estimated by Lazar d (see Table 8 above) which likewise reflect a similar level of cost uncertainty. The Lazard nuclear costs show a range of projected levelized capital cost from $73/MWh to $110/MWh – a range of 50 percent, very similar to the 40 percent range (i.e, -10 percent to +30 percent) suggested by EIA nuclear experts. T he Global CCS

343 EIA does not provided uncertainty estimates in the AEO cost projections. However, EIA staff have indicated to t he EPA that a range of uncertainty of -10%/+30% on the capital co mponent of the LCOE can be expected based on market uncertaint ies. See memorandum “Range of uncertainty for AEO nuclear co sts” available in the rulemaking docket, EPA-HQ-OAR-2013 -0495.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 340 of 854 Institute, in its most recent cost update, also pro vides nuclear costs as a range from $86/MWh to $102/MWh. 344 3. Use of Costs from Current Projects Although we are relying on cost estimates drawn fro m techno-economic models, we recognize that there are a few steam electric plants that include CCS that have been bui lt, or are being constructed. Some information about the costs (or cost-todate) for these projects is known. We discuss in th is section the costs at facilities which have installed or are installing CCS, why the EPA does not consider those costs to b e reasonably predictive of the costs of the next new plants to b e built, and why the EPA considers that the next new plants will have lower costs along the lines predicted by NETL. 345

344 “The Costs of CCS and other Low-Carbon Technologie s - 2015 update” July 2015, Global CCS Institute, Available at: http://hub.globalccsinstitute.com/sites/default/fil es/publicatio ns/195008/costs-ccs-other-low-carbon-technologies-2 015- update.pdf. 345 The EPA notes that two of these facilities, Kemper and HECATCEP , received both assistance from DOE under EPAct05 a nd the IRC section 48A tax credit; and that the AEP Mo untaineer pilot project received assistance from DOE under EP Act05. Under the most extreme interpretations of those provision s offered by commenters, the EPA would be precluded from any con sideration of any information from those sources, including cost information, in showing whether a system of emission reduction i s adequately demonstrated. We note, however, that many of these same commenters urged consideration of the cost informat ion from these sources. In fact, the EPA is not relying on i nformation about the costs of these sources to determine the B SER or the standards of performance in this rulemaking, and th e EPA is discussing the cost information here to explain why not.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 341 of 854 The Boundary Dam Unit #3 facility utilizing post-co mbustion capture from Shell Cansolv is now operational. Petr a Nova, a joint venture between NRG Energy Inc. and JX Nippon Oil & Gas Exploration, is currently constructing a post-combu stion capture system at NRG’s WA Parish generating station near H ouston, TX. The post-combustion capture system will utilize MHI amine-based solvents and is currently being constructed with pl ans to initiate operation in 2016. 346 Construction on Mississippi Power’s Kemper County E nergy Center IGCC facility is now nearly complete. The co mbined cycle portion of the facility has been generating power u sing natural gas. The gasification portion of the facility and t he carbon capture system are undergoing system checks and tra ining to enable commercial operations using a UOP SelexolTM p re-combustion capture system in early 2016. 347

OtherAnother full-scale projects – such asproject, the Summit Power Texas Clean Energy Project and the Hydrogen Energy California Project – havehas not commenced construction but

Accordingly, this discussion of cost information fr om these sources is not precluded by the EPAct05 and IRC sec tion 48A provisions and, even if it is precluded, that would have no impact on the EPA’s determination of the BSER and t he standards of performance in this rule. 346 http://www.nrg.com/sustainability/strategy/enhance

generation/carbon-capture/wa-parish-ccs-project //. 347 http://www.mississippipower.com/about-energy/plant s/kempercounty-energy-facility/facts

.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 342 of 854 remainremains a viable projectsproject . Several other full-scale projects have been proposed and have progressed thr ough the early stages of design, but have been cancelled or postponed for a variety of reasons. Some cost information is also available for small demonstration projects – including those that have been supported by USDOE research programs. These project s would include Alabama Power’s demonstration project at Pl ant Barry and the AEP/Alstom demonstration at Plant Mountaineer. Many commenters felt that the EPA should rely on th ose high costs when considering whether the costs are reason able. 348 The costs from these large-scale projects appear to be consistently higher than those projected by techno-economic mode ls. However, the costs from these full-scale projects represent first-of-akind (FOAK) costs and, it is reasonable to expect t hese costs to come down to the level projected in the NETL and ot her technoeconomic studies for the next new projects that are built – which are the sources that would be subject to this standard.

Significant reductions in the cost of CO 2 capture would be consistent with overall experience with the cost of pollution control technology. A significant body of literatur e suggests

348 At other times some of the same commenters insiste d that the EPA is forbidden from considering the costs from an y projects that received funding from the Energy Policy Act of 2005.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 343 of 854 that the per-unit cost of producing or using a give n technology declines as experience with that technology increas es over time, and this has certainly been the case with air pollu tion control technologies. Reductions in the cost of air polluti on control technologies as a result of learning-by-doing, rese arch and development investments, and other factors have bee n observed over the decades. We expect that the costs of captu re technology will follow this pattern.

The NETL cost estimates reasonably account for this documented phenomenon. Specifically, “[I]n all cases, the report “reflect[s] the cost ofintends to represent the next commercial offering for plants that include technologies that are not yet fully mature, and /or which have not yet been serially deployed in a commercial context, e.g. IGCC plants and any p lant with CO2 capture. These relies on vendor cost estimates for next commercial offerings do not include the unique cost premiums associated with first-of-a-kind (FOAK) plants that must demonstratecomponent technologies. It also applies process contingencies at the appropriate subsystem levels i n an attempt to account for expected but undefined costs (a chal lenge for*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 344 of 854 emerging technologies and resolve the cost and performance challenges associated with initial iterations.” 349 ).” 350

Commenters argued that the next plants to be built would still reflect first-of-a-kind costs, pointing to the newness of the technology and the lack of operating experience, i.e. the alleged absence of learning by doing. The EPA disagrees. In addition to operating experience from operating and partially constructed CCS projects, substantial research efforts are underway providing a further knowledge base to reduce CO 2 capture costs and to improve performance

. Research is underway to reduce CO 2 capture costs and to improve performance. The DOE/NETL sponsors an extensive research, development and demonstration program tha t is focused on developing advanced technology options that will dramatically lower the cost of capturing CO 2 from fossil - fuel energy plants compared to currently available capture technologie s. The largescale CO 2 capture demonstrations that are currently planned and in some cases underway, under DOE’s initiatives, as well as other domestic and international projects, will gen erate operational knowledge and enable continued commerci alization and deployment of these technologies. Gas absorption pr ocesses using

349 NETL p. 37. 350 “Cost and Performance Baseline for Fossil Energy P lants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 3 8.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 345 of 854 chemical solvents, such as amines, to separate CO 2 from other gases have been in use since the 1930s in the natur al gas industry and to produce food and chemical grade CO 2 . The advancement of amine-based solvents is an example o f technology development that has improved the cost and performa nce of CO 2 capture. Most single component amine systems are no t practical in a flue gas environment as the amine will rapidly degrade in the presence of oxygen and other contaminants. The Fluor Econamine FG process, the process modeled in the NE TL cost study for the SCPC cases, uses a monoethanolamine (MEA) f ormulation specially designed to recover CO 2 and contains a corrosion inhibitor that allows the use of less expensive, co nventional materials of construction. Other commercially avail able processes use sterically hindered amine formulation s (for example, the Mitsubishi Heavy Industries KS–1 solve nt) which are less susceptible to degradation and corrosion issue s. The DOE/NETL and private industry are continuing to sponsor research on advanced solvents (including new classe s of amines) to improve the CO 2 capture performance and reduce costs. To facilitate the transfer of the technology and to accelerate development of carbon capture technology As noted in Section V.H.7.d above , SaskPower has created the CCS Global Consortium to facilitate further knowledge regarding, and use*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 346 of 854 of, carbon capture technology

. 351 This consortium provides SaskPower the opportunity to share its knowledge an d experience with global energy leaders, technology developers, and project developers. SaskPower, in partnership with Mitsubis hi and Hitachi, is also helping to advance CCS knowledge a nd technology through the creation of the Shand Carbon Capture Te st Facility (CCTF). 352 The test facility will provide technology develope rs with an opportunity to test new and emerging carbon capture systems for controlling carbon emissions from coal- fired power plants. We also note certain features of the commercial pla nts already built that suggestssuggest that their costs are uniquely high, and otherwise not fairly comparable to the co sts of plants meeting the NSPS using the BSER. Most obviously, all of these projects involve full rather than partial CCSMost o bviously, many of these projects involve deeper capture than the partial CCS that the EPA assumes in this final action. In a ddition, cost overruns at the Kemper facility, mentioned repeated ly in the public comments, resulted in major part from highly idiosyncratic circumstances, and are related to the cost of the

351 http://www.saskpowerccs.com/consortium //. 352 http://www.saskpowerccs.com/ccs-projects/shand-car boncapture-test-facility //.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 347 of 854 IGCC system, not to the cost of CCS. 353 The EPA does not believe that these unusual circumstances are a reasonable b asis for assessing costs of either CCS or IGCC here

. In addition, we note that the Administration’s CCS Task Force report recognized that CCS would not become m ore widely available without the advent of a regulatory framew ork that promoted CCS or a provided a strong price signal fo r CO 2 . Today’s action is an important component in developing that framework. 4. Cost Competitiveness of New Coal Units As the EPA noted, all indications suggest that very few new coal-fired power plants will be constructed in the foreseeable future. Although a small number of new coal-fired p ower plants

353 See Independent Monitor’s Prudency Evaluation Repo rt for the Kemper County IGCC Project (prepared for Mississipp i Public Utilities Staff), available at www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?m odel=INSITE_C ONNECT&queue=CTS_ARCHIVEQ&docid=328417 (“Report”). As documented in this Report, costs escalated significantly becau se the developers adopted a “compressed schedule” in an at tempt to obtain the IRC 48A tax credit, resulting in “engine ering and design changes which are a normal result of detaile d engineering and design ... occurring at the same time as, rather than ahead of, construction activities”, which did not allow f or proper sequencing during construction. This “’just-in-time ’ approach to engineering and procurement (meaning that the engin eering was often completed shortly before material procurement and construction activities) resulted in a greater numb er of construction work-arounds, congestion of constructi on craft labor in the field, inefficiencies and additional s teps that became necessary during construction to cope with t his just-intime engineering, procurement and construction appr oach.” Report, p. 6. Ironically, work was still completed too late to obtain the tax credit. Id. p. 15.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 348 of 854 have been built recently, the industry generally is not building these kinds of power plants at present and is not e xpected to do so for the foreseeable future. The reasons include the current economic environment and improved energy efficiency , which has led to lower electricity demand, and competitive cu rrent and projected natural gas prices. On average, the cost of generation from a new NGCC power plant is expected to be lower than the cost of generation from a new coal-fired power plan t , and the EPA has concluded that, even in the absence of the requirements of this final rule, very few new coal-fired power p lants will be built in the near term

. CommentersSome commenters , however, argued thatdisagreed with this conclusion – that without a CCS-based NSPS, no coalfired generation will be built.. They contentedcontended instead that it is the CCS-based NSPS that would preclude s uch new generation. However, as the EPA has discussed, ther e is considerable evidence that utilities and project de velopers are moving away – or have already moved away – from a l ong term dependence on coal-fired generating sources. A revi ew of publicly available integrated resource plans show t hat many utilities are not considering construction of new c oal-fired sources without CCS. There have been very fewSee Section V. H.3

above. Few new coal-fired generating sources builthave commenced construction in the past 5 years and, of the projects that are*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 349 of 854 currently in the development phase, the EPA is only aware of projects that will include CCS in the design. As we have noted in this preamble, the bulk of new generation that h as been added recently has been either natural gas-fired or renew able sources. Overall, the EPA remains convinced that the energy sector modeling is reflecting the realities of the market in predicting very few new coal-fired power plants in the near fu ture – even in the absence of these final standards. In addition, we note that the Administration’s CCS Task Force report recognized that CCS would not become m ore widely available without the advent of a regulatory framew ork that promoted CCS or provided a strong price signal for CO 2 . In this regard, we note American Electric Power’s statement s regarding the need for federal requirement for GHG control to aid in cost recovery for CCS projects, to attract other investm ent partners, and thereby promote advancement and deployment of C CS technology: “as a regulated utility, it is impossib le to gain regulatory approval to recover our share of the cos ts for validating and deploying the technology without fed eral requirements to reduce greenhouse gas emissions alr eady in place. The uncertainty also makes it difficult to a ttract partners to help fund the industry’s share”. 354 Indeed, AEP has

354 www/aep.com/newsroom/newsreleases/?id=1704.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 350 of 854 stated that CCS is important for the very future of the industry: “AEP still believes the advancement of CC S is critical for the sustainability of coal-fired generation.” 355 This final rule’s action is an important component in developi ng that needed regulatory framework. 5. Accuracy of Cost Estimates for Transportation an d Geologic Sequestration The EPA’s estimates of costs include take into account the transport of CO 2 and sequestration of captured CO 2 . Estimates of transport and sequestration costs – approximately $ 5-$15 per ton

of CO 2 - are based on DOE NETL studies and are also consistent with other published studies. 356 For transport, costs reflect

355 “CCS LESSONS LEARNED REPORT American Electric Powe r Mountaineer CCS II Project Phase 1”, prepared for T he Global CCS Institute Project # PRO 004, January 23, 2012, page 2. Available at: www.globalccsinstitute.com/publications/ccs-les sons-learnedreport-american-electric-power-mountaineer-ccs-ii-p roject-phase1; See also AEP FEED Study at pp. 4, 63, Available at: www.globalccsinstitute.com/publications/aep-mountai neer-iiproject-front-end-engineering-and-design-feed-repor t. 356 Updated Costs (June 2011 Basis) for Selected Bitumi nous Baseline Cases (DOE/NETL-341/082312 ;); Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Ca pture (DOE/NETL-2011/1498 ) and); Cost and Performance Baseline for Fossil Energy Plants (DOE/NETL-2010/1397); Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Va lley Authority, NETL and EPRI, December 2002 ; Carbon Dioxide and Transport and Storage Costs in NETL Studies . DOE/NETL-2013/1614. March 2013. (DOE/NETL-2013/1614), March 2013; Carbon Dioxide and Transport and Storage Costs in NETL Studies (DOE/NETL2014/1653), May 2014; Cost and Performance Baseline for Fossil Energy Power Plants, Volume 1a: Bituminous Coal (PC ) and Natural Gas to Electricity (DOE-NETL-2015/1723), July 2015.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 351 of 854 pipeline capital costs, related capital expenditure s, and O&M costs. Sequestration cost estimates reflect the cos t of site screening and evaluation, the cost of injection wel ls, the cost of injection equipment, operation and maintenance c osts, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory re quirements of the Underground Injection Control Class VI program and Greenhouse Gas Reporting ProgramGHGRP subpart RR for geologic sequestration of CO 2 in deep saline formations , which are discussed further in Sections V. M. and N below

. 357 Based on DOE/NETL studies, the EPA estimated that t he total

CO 2 transportation, storage, and monitoring (TSM) cost associated with EGU CCS would comprise less than 5.5 percent o f the total cost of electricity in all capture cases modeled

--- approximately $5-$15 per ton of CO 2 . 358 The range of TSM costs the EPA relied on ( are broadly consistent with estimates provided by the Global Carbon Capture and Storage Institute as well. 359 Some commenters suggested that the EPA underestimated th e costs associated with transporting captured CO 2 from an EGU to a

357 Carbon Dioxide and Transport and Storage Costs in NETL Studies. DOE/NETL-2013/1614. March 2013. P. 13. 358 RIA at section 5.5 ; proposed rule RIA at 5-30. 359 http:// wwwhub .globalccsinstitute.com/ sites/default/files/ publica tions/ 12786/ economic-assessment-carbon-capture-andstoragetechnologiesstorage-technologies -2011-update. pdf.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 352 of 854 sequestration site. 360 Specifically, commenters suggested that the EPA’s estimated costs for constructing pipeline s were lower than costs based on actual industry experience. Com menters also opined that the EPA’s assumed length of pipeline ne eded between the EGU and the sequestration site is not reasonabl e and that

the DOE -/ NETL study upon which the EPA relied does not accou nt for CO 2 transport costs when EOR is not available. The EPA believes its estimates of transportation an d sequestration costs are reasonable. First, the EPA in fact includedincludes cost estimates for CO 2 transport when EOR opportunities are not available – consistent with i ts overall conservative cost methodology of assuming no revenu es from sale of captured CO 2 . Specifically, the EPA estimatedestimates transport, storage and monitoring (TSM) costs of $5 -$15 per ton

of CO 2 for non-EOR applications. 361 This estimate is reflected in the LCOE comparative costs. 362 The EPA also carefully reviewed the assumptions on which the transport cost estimates are based and continue s to find

360 See, for example, comments from American Electric, pp 97-8, Southern Company, pp. 47-48, and Duke Power p. 98. 361 See RIA at and proposed rule RIA at 5-30. For EO R applications the point of sale is typically the fac ility fence line, in which case the CO 2 supplier (i.e. the EGU) will avoid the TSM cost. Consequently, the economic benefit of EOR may be greater than simply the price paid for CO 2 . See RIA at section 5.5 and proposed RIA at 5-30. 362 See RIA at section 5.5

.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 353 of 854 them reasonable. The NETL studies referenced in Sec tion V.I.2 above based transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline. 363 At least one study estimated that of the 500 largest point sources of CO 2 in the United States, 95 percent are within 50 miles of a potential storage reservoir. 364 As a point of reference, the longest CO 2 pipeline in the United States is 502 miles. 365 For new sources, pipeline distance and costs can be factored into si ting and, as discussed in sectionSection V. KM , there is widespread availability of geologic formations for geologic sequestration ( GS .). Moreover, data from the Pipeline and Hazardous Mat erials Safety Administration show that in 2013 there were 5,195 miles

of CO 2 pipelines operating in the United States. This rep resents a seven percent increase in CO 2 pipeline miles over the previous year and a 38 percent increase in CO 2 pipeline miles since 2004. For the reasons outlined above, the EPA believes it s estimates

363 The pipeline diameter was sized for this to be ach ieved without the need for recompression stages along the pipeline length. 364 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gu pta, SH Kim, EL Malone (2006), Carbon Dioxide Capture and G eologic Storage: A Key Component of a Global Energy Technol ogy Strategy to Address Climate Change. Joint Global Change Rese arch Institute, Battelle Pacific Northwest Division. PNW D-3602. College Park, MD. 365 A Review of the CO 2 Pipeline Infrastructure in the U.S., April 21, 2015, DOE/NETL-2014/1681, Office of Fossil Ener gy, National Energy Technology Laboratory.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 354 of 854 have a reasoned basis. See also sectionSection V. KM below further discussing the current availability of CO 2 pipelines. With respect to sequestration, certain commenters a rgued that the EPA’s cost analysis failed to account for many contingencies and uncertainties (surface and sub-su rface property rights in particular), ignored the costs o f Greenhouse Gas Reporting ProgramGHGRP subpart RR, and also was not representative of the costs associated with specifi c GS site characterization, development, and operation/inject ion of monitoring wells. Commenter American Electric Power (AEP) referred to its own experience with the Mountaineer demonstration project. AEP noted that although this project was not full scale, finding a suitable repository, notw ithstanding a generally favorable geologic area, proved difficult . The company referred to its estimated cost of expanding the exi sting Mountaineer plant to a larger scale project, partic ularly the cost of site characterization and well construction

. 366 The EPA’s cost estimates account for the requiremen ts of the Underground Injection Control Class VI program, and Greenhouse Gas Reporting ProgramGHGRP subpart RR, among them site screening and evaluation costs, costs for inje ction wells and equipment, O&M costs, and monitoring costs. The estimated

366 AEP Comments at pp. 93, 96.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 355 of 854 sequestration costs include operational and post-in jection site care monitoring, which are components of the UIC Cl ass VI requirements, and also reflect costs for sub-surfac e pore volume property rights acquisition. 367 These estimates are consistent with the costs presented in the study CO 2 Storage and Sink Enhancements: Developing Comparable Economics , which incorporates the costs associated with site evaluat ion, well drilling, and the capital equipment required for tr ansporting and injecting CO 2 . 368,369 Monitoring costs were evaluated based on the methodology set forth in the International Ener gy Agency Greenhouse Gas R&D Programme’s Overview of Monitoring Projects for Geologic Storage Projects report. 370

367 NETL p. “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture.” DOE/NETL-2011/149 8 (September 2013) p. 49. Specifically, the report estimates the costs associated with acquiring rights to use the pore sp ace in the geologic formation. Costs are estimated based on st udies of subsurface rights acquisition for natural gas stora ge. The report also estimates costs for land acquisition fo r surface property rights. Id. p. 48. 368 Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davids on, D G. De La Torre Ugarte, and D. Simbeck. (2003). Economic E valuation of CO 2 Storage and Sink Enhancement Options, Final Techni cal Report Prepared by Tennessee Valley Authority for DOE. 369 As noted above, other sequestration-related costs are also estimated, including injection wells and equipment, pore volume acquisition, and long-term-liability. “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bitumin ous Coal and Natural Gas to Electricity Revision 2a, Septemb er 2013 DOE/ NETL (2013) pp. 49-50-2010/1397, p. 55

. 370 “ Overview of Monitoring Requirements for Geologic St orage Projects .”, IEA Greenhouse Gas R&D Programme, Report Number PH4/29, November 2004.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 356 of 854 The EPA’s cost estimates for sequestration thus cov er all aspects commenters claimed the EPA disregarded. The EPA believes that the use of costs and scenarios presented in th e studies referenced are representative for purposes of the c ost analysis. The NETL cost estimates upon which the EPA’s costs draw directly from the UIC Class VI economic impact analysis. 371 That analysis is based on estimated characteristics for a represe ntative group of projects over a 50-year period of analysis, as w ell as industry averages for several cost components and s ubcomponents. The EPA also made reasonable assumptions regarding the assumed injection site: a deep saline formation with typical characteristics (e.g., depth and pressure). 372 To that end, the EPA believes that the use of the costs and scenario s presented in these studies referenced are representative for the purposes of the cost analysis.representative depth and press ure). 373 With respect to AEP’s experience with the Mountaine er demonstration project, sequestration siting issues are of course

371 Cost Analysis for the Federal Requirements Under t he Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells, U.S. Environm ental Protection Agency Office of Water, EPA 816-R10-013, November 2010, pages 3-1, 5-42. 372 Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002. 373 Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 357 of 854 site-specific, and raise individual issues. For this reason, it is inappropriate to generalize from a particular in dividual experience. In this regard, as explained in Section V. LN below, the construction permits issued by the EPA to-date under the Underground Injection Control Class VI regulations required far fewer wells for site characterization and monitorin g than AEP found to be necessary at its Mountaineer site. Mor eover, notwithstanding difficulties, the company was able to successfully drill and complete wells, and safely i nject captured CO 2 . Moreover, theThe company also indicated it fully expected to be able to do so at full scale and expl ained how. 374 For discussion of 40 CFR Partpart 98 subpart RR (the Greenhouse Gas Reporting ProgramGHGRP requirements for geologic sequestration), including costs associated with com pliance with those requirements, see sectionSection V. LN below. J. AchievableJ. Achievability of the Final Standard s The EPA finds the final standard of 1,400 lb CO 2 /MWh-g to be achievable over a wide range of variable conditions that are reasonably likely to occur when the system is prope rly designed

374 See AEP FEED Study at pp. See “CCS front end engine ering & design report: American Electric Power Mountaineer CCS II Project. Phase 1” at pp. 36-43. The company likewise explained the monitoring regime it would utilize to verify co ntainment, and the well construction it would utilize to guara ntee secure sequestration. Id. at pp. 44-54. Available at: http://www.globalccsinstitute.com/publications/aep- mountaineerii-project-front-end-engineering-and-design-feed-re port.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 358 of 854 and operated. As discussed elsewhere, the final sta ndard reflects the degree of emission limitation achievab le through the application of the BSER which we have determine d to be a highly efficient SCPC implementing partial CCS at a level sufficient to achieve the final standard – for such a unit utilizing bituminous coal that would be approximate ly 16 percent. In determining the predicted cost and perf ormance of such a system, the EPA utilized information contain ed in updated DOE/NETL studies that assumed use of bituminous coa l and an 85 percent capacity factor. Here we examine the effect s of deviating from those assumed operational parameters on the achievability of the final standard of performance. 375 This is in keeping with the requirement that a standard of per formance must be achievable accounting for all normal operating v ariability when a control system is properly designed, maintai ned, and operated. See Section III.H.1.c above. 1. Operational Fluctuations, Start-ups, Shutdowns, and Malfunctions Importantly, compliance with the standard must be demonstrated over a 12-operating-month average. The total CO 2 emissions (pounds of CO 2 ) over 12 operational months are summed

375 Additional information can be found in a Technical Support Document (TSD) – “Achievability of the Standard for Newly Constructed Steam Generating EGUs” available in the rulemaking docket.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 359 of 854 and divided by the total gross output (in megawatt- hours) over the same 12 operational months. Such a compliance a veraging period is very forgiving of short-term excursions t hat can be associated with non-routine events such as start-up s, shutdowns, and malfunctions. A new fossil fuel-fired steam gen erating EGU – if constructed – would, most likely, be built to se rve base load power demand and would not be expected to routinely start-up or shutdown or ramp its capacity factor in order to fo llow load demand. Thus, planned start-up and shutdown events would only be expected to occur a few times during the course of a 12- operating-month compliance period. Malfunctions are unplanned and unpredictable events and emission excursions ca n happen at or around the time of the equipment malfunction. Bu t a malfunctioning EGU that cannot be operated properly should be shut down until the malfunctioning equipment can be addressed and the EGU can be restarted to operate properly. The post-combustion capture systems that have been utilized have proven to be reliable. The Boundary Dam facili ty has been operating full CCS successfully at commercial scale since October 2014. As described earlier, in evaluating r esults from the Mountaineer slip-stream demonstration, AEP and Alstom reported robust steady-state operation during all m odes of power*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 360 of 854 plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent. 376 2. Variations in Coal Type The use of specific coal types can affect the amoun t of CO 2 that is emitted from a new coal-fired power plant. As previously discussed, the EPA utilized studies by the DOE/NETL to predict the cost and performance of new steam generating un its. Based on those reports, the EPA predicts that a new SCPC bur ning low rank coal (subbituminous coal or dried lignite) would ha ve an uncontrolled emission rate about 7 percent higher t han a similar unit firing typical bituminous coal. 377 The EPA predicts that such a highly efficient new SCPC utilizing subbitum inous coal or dried lignite would need to capture approximately 2 3 percent of

the CO 2 . The EPA also believes that it is technically feas ible to do so, although additional cost would be entailed. The EPA has

376 http://www.alstom.com/press-centre/2011/5/alstom-a nnouncessucessful-results-of-mountaineer-carbon-capture-and

sequestration-ccs-project/. The Boundary Dam facili ty likewise is operating reliably (see Section V.D.3.a above). See also “Cost and Performance Baseline for Fossil Energy Pl ants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electri city, Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 3 6 (“[t]he capture and CO 2 compression technologies have commercial operating experience with demonstrated ability for high reliability”). 377 For additional detail, see the Technical Support D ocument (TSD) – “Achievability of the Standard for Newly Co nstructed Steam Generating EGUs” – available in the rulemakin g docket.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 361 of 854 evaluated those costs and finds them to remain reas onable. 378 As shown in Table 8 above, the predicted cost remains within the estimated range for the other principal base load, dispatchable non-NGCC alternative technologies. Estimated capita l cost using these coal types would also be somewhat higher, an estimated 23 percent increase. 379 The EPA finds these increases to be reasonable because, as discussed earlier, the costs are reasonably consistent with capital cost increases i n previous NSPS. See Section V.H.4 above.

K. Emission Reductions Utilizing Partial CCS Although the definition of “standard of performance ” does not by its terms identify the amount of emissions f rom the category of sources and the amount of emission redu ctions achieved as factors the EPA must consider in determ ining the “best system of emission reduction,” the D.C. Circu it has stated

that the EPA must do so. See Sierra Club v. Costle , 657 F.2d 298,at 326 (D.C. Cir. 1981) (“we can think of no sensible interpretation of the statutory words “best ... syste m” which

378 The cost of the lignite drying equipment is assume d to be low compared to the cost of the carbon capture equipmen t. Further, pre-drying of the lignite reduces fuel, auxiliary p owerconsumption and other O&M costs. www.ieacoal.org.uk/documents/83436/9095/Techno-economics-o f-modern-predrying-technologies-for-lignite-fired-power-plants, -CCC/241. 379 Note that the 23 percent increase in expected capi tal costs and the 23 percent CO 2 capture needed to meet the final standard are coincidental and are not correlated.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 362 of 854 would not incorporate the amount of air pollution a s a relevant factor to be weighed when determining the optimal s tandard for controlling ... emissions”). 380 This is consistent with the Court’s statements in Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427 (D.C. Cir. 1973)at 437 that it is necessary to “[k]eep [ ][] in mind Congress’ intent that new plants be controlled to the ‘maximum practicable degree.’”degree’”. The final standard of performance will result in me aningful and significant emission reductions of GHG emission s from a new coal-fired steam generating unit. The EPA estimates that a new highly efficient 500 MW coal-fired SCPC meeting the final standard of 1,400 lb CO 2 /MWh- grossg will emit about 640354 ,000 fewer metric tons of CO 2 each year than that new highly efficient unit would have emitted otherwise. That is equivale nt to taking

about 135,40075,000 vehicles off the road each year 381 and will result in over 2514 ,000,000 fewer metric tons of CO 2 in a 40-year operating life. To emphasize the importance of constructing a highly efficient SCPC unit that includes partial CC S - the

380 Sierra Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981) was governed by the 1977 CAAA version of the definition of “standard of performance,” which revised the phrase ‘‘best sy stem’’ to read, “best technological system.” The 1990 CAAA de leted “technological,” and thereby returned the phrase to how it read under the 1970 CAAA. The Sierra Club v. Costle ’s interpretation of this phrase to require consideration of the amou nt of air emissions remains valid for the phrase “best system .” 381 Using U.S. EPA Office of Transportation and Air Qu ality (OTAQ) estimate of average vehicle emissions of 4.7 tonnes/year.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 363 of 854 highly efficient 500 MW coal-fired SCPC with partia l CCS would emit about 675,000 fewer metric tons of CO 2 each year than that from a new, less efficient coal-fired utility boile r with an assumed emission of 1,800 lb CO 2 /MWh-g. For comparison, see Table 1312 below which provides the

amount of CO 2 emissions captured each year by other CCS projects

. These result show that, even though the emission re ductions are significant, they are reasonably within the range o f emission reductions that are currently being achieved now in existing facilities. For comparison, approximately 60,000,000 metric ton s of CO 2 were supplied to U.S. EOR operations in 2013. 382 Table 1312 . Annual Metric Tons of CO 2 Captured (or predicted to capture) from CCS Projects and from a Model 500 MW Plant Meeting the Final Standard. CO 2 captured Project tonnes/year AES Shady Point 66,000 AES Warrior Run 110,000 Southern Company Plant Barry 165,000 Searles Valley Minerals 270,000 New 500 MW SCPC plantEGU (1,400 lb CO 2 /MWhg) 636,300354,000 Coffeyville Fertilizer 700,000 Boundary Dam #3 1,000,000 Petra Nova/NRG WA Parish 1, 600400 ,000 Dakota Gasification 3,000,000 2013 CO 2 supplied to U.S. EOR operations 383 60,000,000

382 Greenhouse Gas Reporting Program, data reported as of August 18, 2014. 383 Greenhouse Gas Reporting Program, data reported a s of August 18, 2014.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 364 of 854

KL . Further Development and Deployment of CCS Technol ogy Researchers at Carnegie Mellon University (CMU ),) have studied thatthe history and the technological response to environmental regulations. 384 By examining U.S. research funding and patenting activity over the past century, the C MU researchers found that promulgation of national pol icy requiring large reductions in power-plant emissions resulted in a significant upswing in inventive activity to develo p technologies to reduce those emissions. The researc hers found that, following the 1970 Clean Air Act, there was a 10-fold increase in patenting activity directed at improvin g the SO 2 scrubbers that were needed to comply with stringent federal and

state-level standards. Much like carbon capture scrubbers today, the techn ology to capture and remove SO 2 from power plant flue gases was new to the industry and was not yet widely deployed at large c oal-burning plants when the EPA first promulgated the 1971 stan dards.

384 See Technical Support Document/Memorandum “History Of Flue Gas Desulfurization in the United States” (July 11, 2017) summarizing the doctoral dissertation of Margaret R . Taylor, “The Influence of Government Actions on Innovative Activities in the Development of Environmental Technologies to Co ntrol Sulfur Dioxide Emissions from Stationary Sources,” MA diss ertation submitted to the Carnegie Institute of Technology, Carnegie Mellon University in partial fulfillment of the req uirements for the degree of Doctor of Philosophy in Engineering a nd Public Policy, Pittsburgh, PA, January 2001.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 365 of 854 Many of the early Flue Gas Desulfurization ( FGD ) units didn'tdid not perform well , as the technology at that time was poorly understood and there was little or no prior experience on coal-fired power plants. 385 In contrast, amine-based capture systems have a much longer history of reliable use at coal-fired plants and other industrial sources. There is also a goodbetter understanding of the amine process chemistry and ov erall process design – and project developers have much sophistic ated analytical tools available today than in the 1970s during the development of flue gas desulfurization ( FGD ) scrubber technologies. While R&D efforts were essential to achieving impro vements in FGD scrubber technology – and are also very impo rtant to improving carbon capture technologies, the influenc e of regulatory actions that establish commercial market s for advanced technologies cannot be minimized. The existence of national government regulation for SO 2 emissions control stimulated innovation, as shown by the patent analy sis following initial SO 2 regulatory requirements for EGU emissions. The stu dy author further found that regulatory stringency app ears to be

385 “The Influence of Government Actions on Innovative Activities in the Development of Environmental Technologies to Control Sulfur Dioxide Emissions from Stationary Sources”, PhD Thesis of M.R. Taylor, Engineering and Public Policy, Carnegi e Mellon University (2001).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 366 of 854 particularly important as a driver of innovation, b oth in terms of inventive activity and in terms of the communica tion processes involved in knowledge transfer and diffus ion. Further, as electric power generation doubled, the operating and maintenance costs of FGD systems decline to 83 perc ent of their original level. This finding, which is very much in line with progress ratios determined in other industries, sho ws that quantifiable technological improvements can be show n to occur solely on the basis of the experience of operating an environmental control technology forced into being by government actions. L. GeologicM. Technical and Geographic ConsiderationsAspects of Disposition of Captured CO 2 In the following sections of the preamble, we discu ss issues associated with the disposition of captured CO 2 : the “S” - sequestration – in CCS. We show that geologic sequestration (GS) capacity is available d omestically in the form of geologic formations (e.g., deep sali ne formations) and EOR sites in most areas of the coun try. Where such GS capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants buil t in neighboring areas with GS. For other of those areas , coal-fired power plants are either not being built due to stat e law prohibitions against building such units, or other available Formatted: Font: Times New Roman*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 367 of 854 compliance alternatives exist allowing a new coal-f ired power plant meeting the promulgated NSPS to be sited. We further show that GS can be conducted safely, st oring the sequestered CO 2 without environmental release for geologic time periods. sequestration – in CCS. In this secti on, we review the existing processes, technologies, and geologic conditions that enable successful geologic sequestration (GS). In Section V.N., we discuss in detail the comprehensive, in-pl ace regulatory structure that is currently available to oversee GS projects and assure their safety and effectiveness. Together, these discussions demonstrate that the technical fe asibility of GS, another key component of a partial CCS unit, is adequately

demonstrated. Sequestration is already well proven. CO 2 has been retained underground for eons in geologic (natural) repositories and the mechanisms by which CO 2 is trapped underground are well understood. The physical and chemical trapping mech anisms, along with the regulatory requirements and safeguards of the Underground Injection Control Program and complemen tary monitoring and reporting requirements of the Greenhouse Gas Reporting ProgramGHGRP , together ensure that sequestered CO 2 will remain secure and provide the monitoring to identif y and address*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 368 of 854 potential leakage using Safe Drinking Water Act (SD WA) and CAA authorities (see Section LV.N of this preamble). 386 1. Geologic and Geographic Considerations for GS Geologic sequestration (GS) (i.e., long-term containment of

a CO 2 stream in subsurface geologic formations) is techn ically feasible and available throughout most of the Unite d States. GS is based on a demonstrated understanding of the pro cesses that

affect CO 2 fate in the subsurface; these processes can vary regionally as the subsurface geology changes. GS oc curs through a combination of mechanisms including: 1) structura l and stratigraphic trapping (generally trapping below a low permeability confining layer); 2) residual CO 2 trapping (retention as an immobile phase trapped in the pore spaces of the geologic formation); 3) solubility trapping (di ssolution in the in situ formation fluids); 4) mineral trapping (reaction with the minerals in the geologic formation and con fining layer to produce carbonate minerals); and 5) preferential adsorption

386 See also Carbon Sequestration Council and Southern Company Services v. EPA , No. 14-1406 (D.C. Cir. June 2, 2015) at *10 (“[c]arbon capture and storage is an emerging clima te change mitigation program that involves capturing carbon d ioxide from industrial sources, compressing it into a ‘supercri tical fluid,’ and injecting that fluid underground for the purpos es of geologic sequestration, with the goal of preventing the carbon from reentering the atmosphere. Because the last of these steps – geologic sequestration of the supercritical carbo n dioxide – involves that injection of fluid into underground w ells, it is subject to regulation under the Safe Drinking Water Act”).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 369 of 854 trapping (adsorption onto organic matter in coal an d shale). 387 These mechanisms are functions of the physical and chemical properties of CO 2 and the geologic formations into which the CO 2 stream is injected. Subsurface formations suitable for GS of CO 2 captured from affected EGUs are geographically wide spread throughout most parts of the United States. Storage security is expected to increase over time through post-closure, resulting in a decrease in potential risks. 388 This expectation is based in part on a technical underst anding of the variety of trapping mechanisms that work to reduce CO 2 mobility over time. 389 In addition, site characterization, site operations, and monitoring strategies can work in c ombination to promote storage security. The effectiveness of long-term trapping of CO 2 has been demonstrated by natural analogs in a range of geolo gic settings

where CO 2 has remained trapped for millions of years. 390 For example, CO 2 has been trapped for more than 65 million years in

387 See, e.g., USEPA. 2008. Vulnerability Evaluation F ramework for Geologic Sequestration of Carbon Dioxide. 388 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 47. 389 See, e.g., Intergovernmental Panel on Climate Chan ge. (2005). Special Report on Carbon Dioxide Capture and Storag e. 390 Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale. 2007. Natural Emissions of CO 2 from the Geosphere and their Bearing on the Geological Storage of Carbon Dioxide . Energy 32: 1194–1201.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 370 of 854 the Jackson Dome, located near Jackson, Mississippi

. 391 Other examples of natural CO 2 sources include Bravo Dome and McElmo Dome in Colorado and New Mexico, respectively. Thes e natural storage sites are themselves capable of holding vol umes of CO 2 that are larger than the volume of CO 2 expected to be captured from a fossil fuel-fired EGU. In 2010, the Departme nt of Energy (DOE) estimated current CO 2 reserves of 594 million metric tons at Jackson Dome, 424 million metric tons at Bravo D ome, and 530 million metric tons at McElmo Dome. 392 GS is feasible in different types of geologic forma tions including deep saline formations (formations with h igh salinity formation fluids) or in oil and gas formations, suc h as where injected CO 2 increases oil production efficiency through a process referred to as enhanced oil recovery (EOR). Both deep saline and oil and gas formation types are widely a vailable in the United States. The geographic availability of d eep saline formations and EOR is shown in Figure 1 below. 393 As shown in the figure, there are 39 states for which onshore and o ffshore deep

391 Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage. 392 DiPietro, P., Balash, P. & M. Wallace. A Note on S ources of CO 2 Supply for Enhanced-Oil Recovery Operations. SPE E conomics & Management. April 2012. 393 A color version of the figure, which readers may f ind easier to view, can be found in the technical support docu ment on geographic availability in the rulemaking docket.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 371 of 854 saline formation storage capacity has been identifi ed. 394 EOR operations are currently being conducted in 12 stat es. An additional 17 states have geology that is amenable to EOR operations. Figure 1 also shows areas that are within 100 kilometers (62 miles) of where storage capacity has been identified. 395 There are 10 states with operating CO 2 pipelines

and 2318 states that are within 150100 kilometers (62 miles ) of an active EOR location.

CO 2 may also be used for other types of enhanced recov ery, such as for natural gas production. Reservoirs such as unmineable coal seams also offer the potential for geologic storage. 396 Enhanced coalbed methane recovery is the process o f injecting and storing CO 2 in unmineable coal seams to enhance methane recovery. These operations take advantage o f the preferential chemical affinity of coal for CO 2 relative to the methane that is naturally found on the surfaces of coal. When CO 2 is injected, it is adsorbed to the coal surface and releases methane that can then be captured and produced. Thi s process

394 Alaska is not shown in Figure 1; it has deep salin e formation storage capacity, geology amenable to EOR operation s, and potential GS capacity in unmineable coal seams . 395 The distance of 100 kilometers reflects assumption s in DOENETL cost estimates which the EPA used for cost est imation purposes. See “Carbon Dioxide and Transport and Sto rage Costs in NETL Studies”, DOE/NETL-2014/1653 (May 2014). 396 Other types of opportunities include organic shale s and basalt.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 372 of 854 effectively “locks” the CO 2 to the coal, where it remains stored. DOE has identified over 54 billion metric tons of p otential CO 2 storage capacity in unmineable coal across 21 state s. 397 The availability of unmineable coal seams is shown in F igure 1

below. As discussed below in Sections K.1 and K.2 of this preambleSection M.7 , a few states do not have geologic conditions suitable for GS, or may not be located i n proximity to these areas. However, in some cases, demand in t hose states can be served by coal-fired power plants located in areas suitable for GS, and in other cases, coal-fired pow er plants are unlikely to be built in those areas for other reaso ns, such as the lack of available coal or state law prohibition s and restrictions against coal-fired power plants. 398

397 The United States 2012 Carbon Utilization and Stor age Atlas, Fourth Edition, U.S. Department of Energy, Office o f Fossil Energy, National Energy Technology Laboratory (NETL ). 398 Similarly, as discussed below, the U.S. territorie s lack available coal, do not currently have coal-fired po wer plants, and, as a result, are not expected to see new coal- fired power plants. Hawaii is not expected to constructed new coal pla nts as it intends to utilize 100 percent renewable energy sources by 2050.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

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This image cannot currently be displayed.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

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Figure 1: Geologic Sequestration in the Continental United

States*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 375 of 854*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 376 of 854*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 377 of 854 Figure 2 – Electrical Transmission Lines Acrossacross the Continental United States 399

12 . Availability of Geologic Sequestration in Deep Sa line Formations The DOE and the United States Geological Survey (US GS) have independently conducted preliminary analyses of the availability and potential CO 2 sequestration capacity of deep saline formations in the United States. DOE estimates are compiled by the DOE’s National Carbon Sequestration Database an d Geographic Information System (NATCARB) using volumetric model s and published in a Carbon Utilization and Storage Atlas

. 400 DOE estimates that areas of the United States with appr opriate geology have a sequestration potential of at least 2,035 billion metric tons of CO 2 in deep saline formations. According to DOE and as noted above, at least 39 states have geologi c characteristics that are amenable to deep saline GS in either onshore or offshore locations. In 2013, the USGS co mpleted its evaluation of the technically accessible GS resourc es for CO 2 in U.S. onshore areas and state waters using probabili stic

399 Ventyx Velocity Suite Online. April 2015. 400 The United States 2012 Carbon Utilization and Stor age Atlas, Fourth Edition, U.S. Department of Energy, Office o f Fossil Energy, National Energy Technology Laboratory (NETL ).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

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assessment. 401 The USGS estimates a mean of 3,000 billion metric

tons of subsurface CO 2 sequestration potential, including saline and oil and gas reservoirs, across the basins studi ed in the United States. The DOE has created a network of seven Regional Car bon Sequestration Partnerships (RCSPs) to deploy large- scale field projects in different geologic settings across the country to demonstrate that GS can be achieved safely, permane ntly, and economically at large scales. Collectively, the sev en RCSPs represent regions encompassing 97 percent of coal-f ired CO 2 emissions, 97 percent of industrial CO 2 emissions, 96 percent of the total land mass, and essentially all the geolog ic sequestration sites in the United States potentiall y available

for GS. 402 The seven partnerships include more than 400 organizations spanning 43 states (and four Canadian provinces). 403 RCSP project objectives are to inject at least one million metric tons of CO 2 . In April 2015, DOE announced that CCS

401 U.S. Geological Survey Geologic Carbon Dioxide Sto rage Resources Assessment Team, 2013, National assessmen t of geologic carbon dioxide storage resources—Results: U.S. Geol ogical Survey Circular 1386, p. 41, http://pubs.usgs.gov/circ/138 6/. 402 http://energy.gov/fe/science-innovation/carbon-cap ture-andstorage-research/regional-partnerships. 403 http://energy.gov/fe/science-innovation/carbon-cap ture-andstorage-research/regional-partnerships.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 379 of 854 projects supported by the department have safely an d permanently stored 10 million metric tons of CO 2 . 404 Eight RCSP “Development Phase” projects have been i nitiated and five of the eight projects are injecting or hav e completed

CO 2 injection into deep saline formations. Three of th ese projects have already injected more than one millio n metric tons each, and one, the Cranfield Site, injected over ei ght million metric tons of CO 2 between 2009 and 2013. 405 Various types of technologies for monitoring CO 2 in the subsurface and air have been employed at these projects, such as seismic me thods (crosswell seismic, 3-D and 4-D seismic, and vertic al seismic profiling), atmospheric CO 2 monitoring, soil gas sampling, well and formation pressure monitoring, and surface and ground water monitoring. 406 No CO 2 leakage has been reported from these sites, which further supports the availability of effectiv e GS.

404 http://energy.gov/articles/milestone-energy-depart mentprojects-safely-and-permanently-store-10-million-me tric-tons

. 405 U.S. Department of Energy, National Energy Technol ogy Laboratory, Project Facts, Southeast Regional Carbo n Sequestration Partnership—Development Phase, Cranfi eld Site and Citronelle Site Projects, NT42590, October 2013. Av ailable at: http://www.netl.doe.gov/publications/factsheets/pro ject/NT42590. pdf. 406 A description of the types of monitoring technolog ies employed at RCSP projects can be found here: http://www.netl.doe.gov/research/coal/carbon-storag e/carbonstorage-infrastructure/regional-partnership-develop ment-phaseiii.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

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23 . Availability of CO 2 Storage via EOR Although the determination that the BSER is adequat ely demonstrated and the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA als o recognizes the potential for securely sequestering CO 2 via EOR. EOR is a technique that is used to increase the pro duction of oil. Approaches used for EOR include steam injec tion, injection of specific fluids such as surfactants an d polymers, and gas injection including nitrogen and CO 2 . EOR using CO 2 , sometimes referred to as “CO 2 flooding” or CO 2 -EOR, involves injecting CO 2 into an oil reservoir to help mobilize the remaining oil to make it more amenable for recovery . The crude oil and CO 2 mixture is then recovered and sent to a separator where the crude oil is separated from the gaseous h ydrocarbons, native formation fluids, and CO 2 . The gaseous CO 2 -rich stream then is typically dehydrated, purified to remove hy drocarbons, re-compressed, and re-injected into the reservoir t o further enhance oil recovery. Not all of the CO 2 injected into the oil reservoir is recovered and re-injected. As the CO 2 moves from the injection point to the production well, some of the CO 2 becomes trapped in the small pores of the rock, or is disso lved in the oil and water that is not recovered. The CO 2 that remains in the reservoir is not mobile and becomes sequestered.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

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The amount of CO 2 used in an EOR project depends on the volume and injectivity of the reservoir that is bei ng flooded and the length of time the EOR project has been in operation. Initially, all of the injected CO 2 is newly received. As discussed above, as the project matures, some CO 2 is recovered with the oil and the recovered CO 2 is separated from the oil and recycled so that it can be re-injected into the res ervoir in addition to new CO 2 that is received. If an EOR operator will not require the full volume of CO 2 available from an EGU, the EGU has other options such as sending the CO 2 to other EOR operators, or sending it to deep saline formation GS facilities.

CO 2 used for EOR may come from anthropogenic or natura l

sources. The source of the CO 2 does not impact the effectiveness of the EOR operation. CO 2 capture, treatment and processing steps provide a concentrated stream of CO 2 in order to meet the needs of the intended end use. CO 2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Mat erials Safety Administration found at 49 CFR part 195 (Transporta tion of Hazardous Liquids by Pipeline) apply regardless of the source of

the CO 2 and take into account CO 2 composition, impurities, and phase behavior. Additionally, EOR operators and tra nsport companies have specifications related to the compos ition of the

CO 2 stream. The regulatory requirements and company*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 382 of 854 specifications ensure EOR operators receive a known and consistent CO 2 stream. EOR has been successfully used at numerous producti on fields throughout the United States to increase oil recovery. The oil industry in the United States has over 40 y ears of experience with EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the Unit ed States. 407 More than half of the projects evaluated in the stu dy have been in operation for more than 10 years, and many have been in operation for more than 30 years. This experience p rovides a strong foundation for demonstrating successful CO 2 injection and monitoring technologies, which are needed for safe and secure GS (see Section LN below) that can be used for deployment of CCS across geographically diverse areas. Currently, 12 states have active EOR operations and most have developed an extensive CO 2 infrastructure, including pipelines, to support the continued operation and g rowth of EOR. An additional 2318 states are within 150100 kilometers (62 miles ) of current EOR operations. See Figure 1 above. The vast majority of EOR is conducted in oil reservoirs in t he Permian Basin, which extends through southwest Texas and so utheast New

407 Koottungal, Leena, 2014, 2014 Worldwide EOR Survey , Oil & Gas Journal, Volume 112, Issue 4, April 7, 2014 (correc ted tables appear in Volume 112, Issue 5, May 5, 2014).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 383 of 854 Mexico. States where EOR is utilized include Alabam a, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklah oma, Texas, Utah, and Wyoming. Several commenters raised concer ns about the

volume of CO 2 used in EOR projects relative to the scale of EGU emissions and the demand for CO 2 for EOR projects. At the project level, the volume of CO 2 already injected for EOR and the duration of operations are of similar magnitude to the duration

and volume of CO 2 expected to be captured from fossil fuel-fired

EGUs. The volume of CO 2 used in EOR operations can be large (e.g., 55 million tons of CO 2 were stored in the SACROC unit in the Permian Basin over 35 years), and operations at a single oil field may last for decades, injecting into multiple parts of the field. 408 According to data reported to the EPA’s Greenhouse Gas Reporting Program ( GHGRP ),, approximately 60 million metric tons

of CO 2 were supplied to EOR in the United States in 2013. 409 Approximately 70 percent of this total CO 2 supplied was produced from natural (geologic) CO 2 sources and approximately 30 percent was captured from anthropogenic sources. 410

408 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. “Evaluation of CO 2 trapping mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of CO 2 injection.” American Journal of Science 310. (2010) : 282-324. 409 Greenhouse Gas Reporting Program, data reported as of August 18, 2014. 410 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 384 of 854 A DOE-sponsored study has analyzed the geographic availability of applying EOR in 11 major oil produc ing regions of the United States and found that there is an opp ortunity to significantly increase the application of EOR to ar eas outside of current operations. 411 DOE-sponsored geologic and engineering analyses show that expanding EOR operations into ar eas additional to the capacity already identified and a pplying new methods and techniques over the next 20 years could utilize 18 billion metric tons of anthropogenic CO 2 and increase total oil production by 67 billion barrels. The study found t hat one of the limitations to expanding CO 2 use in EOR is the lack of availability of CO 2 in areas where reservoirs are most amenable

to CO 2 flooding. 412 DOE’s Carbon Utilization and Storage Atlas identifies 29 states with oil reservoirs amenable t o EOR, 12 of which currently have active EOR operations. A compa rison of the current states with EOR operations and the states w ith potential for EOR shows that an opportunity exists to expand the use of

411 “Improving Domestic Energy Security and Lowering C O 2 Emissions with “Next Generation” CO 2 -Enhanced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Availabl e at:http://www.netl.doe.gov/research/energyanalysis/publications/details?pub=df02ffba-6b4b-472 1-a7b4- 04a505a19185. 412 “Improving Domestic Energy Security and Lowering C O 2 Emissions with “Next Generation” CO 2 -Enhanced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Availabl e at:http://www.netl.doe.gov/research/energyanalysis/publications/details?pub=df02ffba-6b4b-472 1-a7b4- 04a505a19185.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 385 of 854 EOR to regions outside of current areas. The availa bility of anthropogenic CO 2 in areas outside of current sources could drive new EOR projects by making more CO 2 locally available. Some commenters raised concerns that data are extre mely limited on the extent to which EOR operations perma nently sequester CO 2 , and the efficacy of long term storage, or that th e EOR industry does not have the requisite experience with and technical knowledge of long-term CO 2 sequestration. The EPA disagrees with these commenters. Several EOR sites, which have been operated for years to decades, have been studi ed to evaluate the viability of safe and secure long-term sequestration of injected CO 2 . Examples are identified below.

CO 2 has been injected in the SACROC Unit in the Permia n basin since 1972 for EOR purposes. One study evalua ted a portion of this project, and estimated that the injection o perations resulted in final sequestration of about 55 million tons of

CO 2 . 413 This study used modeling and simulations, along wi th collection and analysis of seismic surveys, and wel l logging data, to evaluate the ongoing and potential CO 2 trapping occurring through various mechanisms. The monitorin g at this site demonstrated that CO 2 can become trapped in geologic

413 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. “Evaluation of CO 2 trapping mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of CO 2 injection.” American Journal of Science 310. (2010) : 282-324.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 386 of 854 formations. In a separate study in the SACROC Unit, the Texas Bureau of Economic Geology conducted an extensive g roundwater sampling program to look for evidence of CO 2 leakage in the shallow freshwater aquifers. No evidence of leakage was detected. 414 The International Energy Agency Greenhouse Gas Prog ramme conducted an extensive monitoring program at the We yburn oil field in Saskatchewan between 2000 and 2010 (the si te receiving

CO 2 captured by the Dakota Gasification synfuel plant discussed in Section V. E.2.a above). During that time over 16 million metric tons of CO 2 were safely sequestered as evidenced by soil gas surveys, shallow groundwater monitoring, seismi c surveys and wellbore integrity testing. An extensive shallow gr oundwater monitoring program revealed no significant changes in water chemistry that could be attributed to CO 2 storage operations. 415 The International Energy Agency Greenhouse Gas Prog ramme

414 Romanak, K.D., Smyth, R.C., Yang, C., and Hovorka, S., Detection of anthropogenic CO 2 in dilute groundwater: field observations and geochemical modeling of the Dockum aquifer at the SACROC oilfield, West Texas, USA: presented at the 9th Annual Conference on Carbon Capture & Sequestration , Pittsburgh, PA, May 10-13, 2010. GCCC Digital Publication Serie s #10-06. 415 Roston, B., and S. Whittaker (2010), 10+ years of the IEA-GHG Weyburn-Midale CO 2 monitoring and storage project; success and lessons learned from multiple hydrogeological inves tigations, to be published in Energy Procedia, Elsevier, Proceedi ngs of 10th International Conference on Greenhouse Gas Control Technologies, IEA Greenhouse Gas Programme, Amsterdam, The Nether lands.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 387 of 854 developed a best practices manual for CO 2 monitoring at EOR sites based on the comprehensive analysis of surface and subsurface monitoring methods applied over the 10 years. 416 The Texas Bureau of Economic Geology also has been testing a wide range of surface and subsurface monitoring t ools and approaches to document sequestration efficiency and sequestration permanence at the Cranfield oilfield in Mississippi (see Section KL .1 above). 417 As part of a DOE Southeast Regional Carbon Sequestration Partnership study, Denbury Resources injected CO 2 into a depleted oil and gas reservoir at a rate greater than 1.2 million tons/y ear. Texas Bureau of Economic Geology is currently evaluating the results of several monitoring techniques employed at the Cr anfield project and preliminary findings indicate no impact to groundwater. 418 The project also demonstrates the availability and effectiveness of many different monitoring tech niques for tracking CO 2 underground and detecting CO 2 leakage to ensure CO 2 remains safely sequestered. As discussed in Section KM .1 above and as shown in Figure 1, the United States has widespread potential for s torage, including in deep saline formations and oil and gas formations.

416 Hitchon, B. (Editor), 2012, Best Practices for Val idating CO 2 Geological Storage: Geoscience Publishing, p. 353. 417 http://www.beg.utexas.edu/gccc/cranfield.php. 418 http://www.beg.utexas.edu/gccc/cranfield.php.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 388 of 854 However, some commenters maintained that the EPA’s information regarding availability of GS sites is overly genera l and ignores important individual considerations. A number of co mmenters, for example, maintained that site conditions often make monitoring difficult or impossible, so that sites are not avai lable as a practical matter. 419 Commenter American Electric Power pointed to its own experience in siting monitoring wells for i ts pilot plant Mountaineer CCS project, which involved protr acted time and expense to eventually site monitoring wells. 420 Other commenters noted significant geographic disparity i n GS site availability, claiming absence of sites in southeas tern areas of the country. 421 Project- and site-specific factors do influence whe re CO 2 can be safely sequestered. However, as outlined abo ve, there is widespread potential for GS in the United States. I f an area does not have a suitable GS site, EGUs can either t ransport CO 2 to GS sites via CO 2 pipelines (see Section K.3M.5 below), or they may choose to locate their units closer to GS sites and provide electric power to customers through transmission li nes (see Figure 2 and Section M.7 ). In addition, there are alternative means of complying with the final standards of perf ormance

419 Comments of Southern Co., p. 38. 420 Comments of AEP pp. 93, 96. 421 Comments of Duke Energy, pp. 24-5; UARG, pp. 53, 5 7 citing Cichanowicz (2012).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 389 of 854 whichthat do not necessitate use of partial CCS, so any siti ng difficulties based on lack of a CO 2 repository would be obviated.

See Portland Cement Ass’n v. EPA , 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that the EPA could adopt section 111 standards of performance based on the performance of a kiln type that kilns of older design would have great difficulty satisfy ing, since, among other things, there were alternative methods of compliance available should a new kiln of this older design be built. 34 . Alternatives to Geologic Sequestration Potential alternatives to sequestering CO 2 in geologic formations are emerging. These relatively new poten tial alternatives may offer the opportunity to offset th e cost of CO 2 capture. For example, captured anthropogenic CO 2 may be stored in solid carbonate materials such as precipitated calc ium carbonate (PCC) or magnesium or calcium carbonate, bauxite re sidue carbonation, and certain types of cement through mi neralization. PCC is produced through a chemical reaction process that utilizes calcium oxide (quicklime), water, and CO 2 . Likewise, the combination of magnesium oxide and CO 2 results in a precipitation reaction where the CO 2 becomes mineralized. The carbonate materials produced can be tailored to optimize perf ormance in specific industrial and commercial applications. For example,

theseThese carbonate materials have been used in the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 390 of 854 construction industry and, more recently and innova tively, in cement production processes to replace Portland cem ent. For example, theThe Skyonics Skymine project, which opened its demonstration project in October 2014, is an ex ample of captured CO 2 being used in the production of carbonate products

. This plant converts CO 2 into commercial products. It captures over 75,000 tons of CO 2 annually from a San Antonio, Texas, cement plant and converts the CO 2 into other products, including sodium carbonate, sodium bicarbonate, hydrochloric acid and

bleach. 422 A few commenters suggested that CO 2 utilization technologies alternative to GS are being commercialized, and tha t these should be included as compliance options for this r ule. The rule generally requires that captured CO 2 be either injected on-site for geologic sequestration or transferred offsite t o a facility reporting under 40 CFR subpart RR. The EPA does not believe that the emerging technologies just discussed are suffic iently advanced to unqualifiedly structure this final rule to allow for their use. Nor are there plenary systems of regula tory control and GHG reporting for these approaches, as there ar e for geologic sequestration. Nonetheless, as stated abov e, these

422 http://skyonic.com/technologies/skymine.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 391 of 854 technologies not only show promise, but could poten tially be demonstrated to show permanent storage of CO 2 . Alternative technologies that use captured CO 2 , such as the Skyonics project, are innovative advancements for C O 2 utilization that are under development. However, consideration of how these emerging alternatives could be used to meet the per formance standard involves understanding the ultimate fate o f the captured CO 2 and the degree to which the method permanently isolates the CO 2 from the atmosphere. Unlike GS, currently there is not a monitoring and reporting mechanism to demo nstrate that these alternative end uses of captured CO 2 would result in permanent sequestration of the CO 2 . Therefore, they cannot be used to meet the performance standard at this time. As these alternative technologies are developed, the EPA is committed to working collaboratively with stakeholders to evalua te the efficacy of alternative sequestration technologies, address any regulatory hurdles, and develop appropriate monitor ing and reporting protocols in the future. 4In the January 2014 proposal, the EPA noted that i t would need to adopt a mechanism to evaluate these alterna tive technologies before any could be used in lieu of ge ologic sequestration. 79 FR at 1484. The EPA is establishi ng such a mechanism in this final rule. See §60.5555(g). The rule provides for a case-by-case adjudication by the EPA of appli cations*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 392 of 854 seeking to demonstrate to the EPA that a non-geolog ic sequestration technology would result in permanent confinement of captured CO 2 from an affected EGU. The criteria to be addressed in the application, and evaluated by the EPA, are drawn from CAA section 111(j), which provides an an alogous mechanism for case-by-case approval of innovative t echnological systems of continuous emission reduction which have not been adequately demonstrated. Applicants would need to d emonstrate that the proposed technology would operate effectiv ely, and that captured CO 2 would be permanently stored. Applicants must also demonstrate that the proposed technology will not c ause or contribute to an unreasonable risk to public health , welfare or safety. In evaluating applications, the EPA may con duct tests itself or require the applicant to conduct testing in support of its application. Any application would be publicly noticed, and the EPA would solicit comment on the application an d on intended action the EPA might take. The EPA could also provi de a conditional approval of an application on operating results from a proscribed period. The EPA could also terminate a n approval, including a termination based on operating results calling into question a technology’s effectiveness. As noted at proposal, given the unlikelihood of new coalfired EGUs being constructed, the EPA does not expe ct there to*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 393 of 854 be many (if any) applications for use of non-geolog ic sequestration technology. 79 FR at 1484.

5 . Availability of Existing or Planned CO 2 Pipelines

CO 2 pipelines are the most economical and efficient me thod of transporting large quantities of CO 2 . 423 CO 2 has been transported via pipelines in the United States for nearly 40

years. Over this time, the design, construction, operatio n, and safety requirements for CO 2 pipelines have been proven, and the

U.S. CO 2 pipeline network has been safely used and expanded

. The Pipeline and Hazardous Materials Safety Administrat ion (PHMSA) reported that in 2013 there were 5,195 miles of CO 2 pipelines operating in the United States. This represents a s even percent increase in CO 2 pipeline miles over the previous year and a 38 percent increase in CO 2 pipeline miles since 2004. 424 Some commenters argued that the existing CO 2 pipeline capacity is not adequate and that CO 2 pipelines are not available in a majority of the United States. The EPA does not agree. The CO 2 pipeline network in the United States has almost doubled in the past ten ye ars in order to meet growing demands for CO 2 for EOR. CO 2 transport companies

423 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 36. 424 “Annual Report Mileage for Hazardous Liquid or Car bon Dioxide Systems”, U.S. Pipeline and Hazardous Materials Saf ety Administration, March 2, 2015. Available at: http://www.phmsa.dot.gov/pipeline/library/data-stat s.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 394 of 854 have recently proposed initiatives to expand the CO 2 pipeline network. Several hundred miles of dedicated CO 2 pipeline are under construction, planned, or proposed, including projects in Colorado, Louisiana, Montana, New Mexico, Texas, an d Wyoming. Examples are identified below. Kinder Morgan has reported several proposed pipelin e projects including the proposed expansion of the ex isting Cortez

CO 2 pipeline, crossing Colorado, New Mexico, and Texas , to increase the CO 2 transport capacity from 1.35 billion cubic feet per day (Bcf/d) to 1.7 Bcf/d, to support the expans ion of CO 2 production capacity at the McElmo Dome production f acility in Colorado. The Cortez pipeline expansion is expected to be placed into service in 2015. 425 Denbury reported that the company utilized approxim ately 70 million cubic feet per day of anthropogenic CO 2 in 2013 and that an additional approximately 115 million cubic feet per day of anthropogenic CO 2 may be utilized in the future from currently planned or future construction of facilities and as sociated

425 “Form 10-K: Annual Report Pursuant to Section 13 or 15(d) of the Security and Exchange Act of 1934, For the Fisc al Year Ended December 31, 2014”, Kinder Morgan, February 2015. A vailable at: http://ir.kindermorgan.com/sites/kindermorgan.inves torhq.busines swire.com/files/report/additional/KMI-2014-10K_Fina l.pdf.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 395 of 854 pipelines in the Gulf Coast region. 426 Denbury also initiated transport of CO 2 from a Wyoming natural gas processing plant in 2013 and reported transporting approximately 22 mil lion cubic feet per day of CO 2 in 2013 from that plant alone. 427 Denbury completed the final section of the 325-mile Green Pipeline for transporting CO 2 from Donaldsonville, Louisiana, to EOR oil fields in Texas. 428 Denbury completed construction and commenced operation of the 232-mile Greencore Pipel ine in 2013; the Greencore pipeline transports CO 2 to EOR fields in Wyoming

and Montana. 429

A proposed project being constructed by NRG and JX Nippon Oil & Gas Exploration (Petra Nova) would capture CO 2 from a power plant in Fort Bend County, Texas for transport to E OR sites in Jackson County, Texas through a proposedan 82-mile CO 2

426 “2013 Annual Report”, Denbury, April 2014. Availab le at http://www.denbury.com/files/doc_financials/2013/De nbury_Final_0 40814.pdf. 427 “CO 2 Sources”, Denbury, 20142015 . Available at: http://www.denbury.com/operations/rocky-mountain-re gion/co2- sources-and-pipelines/default.aspx. 428 http://www.denbury.com/ responsiblity/publicawareness/Denbury-Awareoperations/gulf-coastregion/Pipelines /default.aspx. 429 “CO 2 Pipelines”, Denbury, 2014. Available at: http://www.denbury.com/operations/rocky-mountain-re gion/COsub2- sub-Pipelines/default.aspx.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 396 of 854 pipeline. 430 The project is anticipated to commence operation i n 2016. 431 Some commenters suggested that there may be challen ges associated with the safety of transporting supercri tical CO 2 over long distances, or that the EPA did not adequately consider the potential non-air environmental impacts of the cons truction of

CO 2 pipelines. The EPA has carefully evaluated the safety of pipel ines used to transport captured CO 2 and determined that pipelines can indeed convey captured CO 2 to sequestration sites with certainty and provide full protection of human health and the environment. 76 FR at 48082-83 (Aug. 8, 2011); 79 FR 352, 254354 (Jan. 3, 2014). Existing and new CO 2 pipelines are comprehensively regulated by the Department of Transportation’s Pip eline Hazardous Material Safety Administration. The regul ations govern pipeline design, construction, operation and mainte nance, and emergency response planning. See generally 49 CFR 1 95.2. Additional regulations address pipeline integrity m anagement by requiring heightened scrutiny to assure the quality of pipeline integrity in areas with a higher potential for adve rse

430 “The West Ranch CO 2 -EOR Project, NRG Fact Sheet”, NRG, 2014. Available at: http:// www.nrg.com/documents/business/pla-2014- west-ranch-fact-sheet.pdf. 431 “WA Parish Carbon Capture Project”, NRG, 2015. Ava ilable at: http:// www.nrg.com/sustainability/strategy/enhancegeneration/carbon-capture/wa-parish-ccs-project/.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 397 of 854 consequences. See 49 CFR 195.450 and 195.452. On-si te pipelines are not subject to the Department of Transportation standards, but rather adhere to the Pressure Piping standards of the American Society of Mechanical Engineers , (ASME B31), which the

EPA has found would ensure that piping and associated equipment meet certain quality and safety criteria sufficient to provide similar protective safeguards as the Departmentprev ent releases

of Transportation regulations. 432 CO 2 , such that certain additional requirements were not necessary ( See 79 FR 358-59 (Jan. 3, 2014 ). The EPA reiterates here its findings that)). 433

These existing controls over CO 2 pipelines assure protective management, guard against releases, and assure that captured CO 2 will be securely conveyed to a sequestration site. 56 . States with Emission Standards That Would Require CCS Several states have established emission performanc e standards or other measures to limit emissions of G HGs from new EGUs that are comparable to or more stringent than the final standard in this rulemaking. For example, in Septem ber 2006, California Governor Schwarzenegger signed into law Senate Bill

432 See the B31 Code for pressure piping, developed by the American Society of Mechanical Engineers, Pipeline Transportation Systems for liquid hydrocarbons and other liquids. 433 See the B31 Code for pressure piping, developed by the American Society of Mechanical Engineers, Pipeline Transportation Systems for liquid hydrocarbons and other liquids.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 398 of 854 1368. The law limits long-term investments in base load generation by the state’s utilities to power plants that meet an emissions performance standard jointly established by the California Energy Commission and the California Pub lic Utilities Commission. The Energy Commission has designed regu lations that establish a standard for new and existing base load generation owned by, or under long-term contract to publicly o wned utilities, of 1,100 lb CO 2 /MWh. In May 2007, Washington Governor Gregoire signed Su bstitute Senate Bill 6001, which established statewide GHG e missions reduction goals, and imposed an emission standard t hat applies to any base load electric generation that commenced operation after June 1, 2008 and is located in Washington, wh ether or not that generation serves load located within the stat e. Base load generation facilities must initially comply with an emission limit of 1,100 lb CO 2 /MWh. In July 2009, Oregon Governor Kulongoski signed Sen ate Bill 101, which mandated that facilities generating base load electricity, whether gas- or coal-fired, must have emissions equal to or less than 1,100 lb CO 2 /MWh, and prohibited utilities from entering into long-term purchase agreements fo r base load electricity with out-of-state facilities that do no t meet that

standard.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 399 of 854

In 2012 New York established emission standards of CO 2 at 925 lb CO 2 /MWh for new and expanded base load fossil fuel-fir ed plants. In May 2007, Montana Governor Schweitzer signed Hou se Bill 25, adopting a CO 2 emissions performance standard for electric generating unitsEGUs in the state. House Bill 25 prohibits the state Public Utility Commission from approving new electric generating unitsEGUs primarily fueled by coal unless a minimum of 50 percent of the CO 2 produced by the facility is captured and sequestered. On January 12, 2009, Illinois Governor Blagojevich signed Senate Bill 1987, the Clean Coal Portfolio Standard Law. The legislation establishes emission standards for new power plants that use coal as their primary feedstock. From 2009 –2015, new coal-fueled power plants must capture and store 50 percent of the carbon emissions that the facility would otherw ise emit; from 2016–2017, 70 percent must be captured and sto red; and after 2017, 90 percent must be captured and stored. 67 . Coal - by - wire

In addition, as discussed in the proposal, electric ity demand in states that may not have geologicalgeologic sequestration sites may be served by coal-fired ele ctricity generation built in nearby areas with geologicalgeologic sequestration, which generationand this electricity can be*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 400 of 854 delivered through transmission lines. This method, known as “coal - by - wire,” has long been used in the electricity sector because siting a coal-fired power plant near the co al mine and transmitting the generation long distances to the l oad area is generally less expensive than siting the plant near the load area and shipping the coal long distances.

For example, we noted in the proposal: “There are m any examples where coal-fired power generated in one st ate is used to supply electricity in other states. For instance , historically, nearly 40 percent of the power for th e City of Los Angeles was provided from two coal-fired power plan ts located in Arizona and Utah. In another example, Idaho Power, which serves customers in Idaho and Eastern Oregon, meets its de mand in part from coal-fired power plants located in Wyoming and Nevada.” 79 FR at 1478. In sum, subsurface formations suitable for GS of CO 2 captured from affected EGUs are geographically wide spread throughout many parts of the United States, includi ng via deep saline formations or EOR. Characteristics of geolog ic formations may vary based on geography, but the mechanisms by which CO 2 is trapped underground are well understood and proven. Additionally, CO 2 pipelines have been operating for over 40 years in the United States and new pipeline projects cont inue to be proposed and built. Some states already impose emis sion limits*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 401 of 854 that can be met only through CCS, and in the few st ates that do not have geologic conditions suitable for GS, or ma y not be located in close proximity to these areas, demand c ould be served by coal-fired generation that is sited in ar eas with GS.

M In the Technical Support Document on Geographic Availability (Geographic Availability TSD), we expl ore in greater detail the issue of coal-by-wire and the ab ility of demand in areas without geologic sequestration to b e served by coal generation located in areas that have access t o geologic sequestration. Figure 1 of this preamble (a color v ersion of which is provided as Figure 1 of the Geographic Ava ilability TSD) depicts areas of the country with: (1) existin g CO 2 pipeline; (2) probable, planned, or under study CO 2 pipeline; (3) counties with active CO 2 -EOR operations; (4) oil and natural gas reservoirs; (5) deep saline formations; (6) unminea ble coal seams; and (7) areas 100 kilometers from geologic s equestration. As demonstrated by Figure 1, the vast majority of t he country has existing or planned CO 2 pipeline, active CO 2 -EOR operations, the necessary geology for CO 2 storage, or is within 100 kilometers of areas with geologic sequestration. 434 A review of Figure 1 indicates limited areas that do not fall i nto these categories.

434 The NETL cost estimates for CO 2 transport assume a pipeline of 100 kilometers. NETL (2015) at p. 44.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 402 of 854 As an initial matter, we note that the data include d in Figure 1 is a conservative outlook of potential are as available for the development of CO 2 storage in that we include only areas that have been assessed to date. Portions of the Un ited States – such as the State of Minnesota -- have not yet been assessed and thus are depicted as not having geological formatio ns suitable

for CO 2 storage, even though assessment could in fact revea l additional formations. 435 As one considers the areas on the map depicted in F igure 1 that fall outside of the above enumerated categorie s, in many instances, we find areas with low population densit y, areas that are already served by transmission lines that could deliver coal-by-wire, and/or areas that have made policy or other decisions not to pursue a resource mix that include s coal. In many of these areas, utilities, electric cooperativ es, and municipalities have a history of joint ownership of coal-fired

435 The data in Figure 1 is based on estimates compile d by the DOE’s National Carbon Sequestration Database and Ge ographic Information System (NATCARB) and published in the U nited States 2012 Carbon Utilization and Storage Atlas, Fourth E dition. As discussed in the TSD, deep saline formation potenti al was not assessed for Alaska, Connecticut, Hawaii, Massachus etts, Nevada, Rhode Island, and Vermont. Oil and gas storage pote ntial was not assessed for Alaska, Washington, Nevada, and Oregon . Unmineable coal seams were not assessed for Nevada, Oregon, Ca lifornia, Idaho, and New York. We are assuming for purposes o f our analysis here that they do not have storage potenti al in those formations.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 403 of 854 generation outside the region or contracting with c oal and other generation in outside areas to meet their demand. S ome of the relevant areas are in RTOs 436 which engage in planning across the RTO, balancing supply and demand in real time throu ghout the RTO. Accordingly, generating resources in one part of the RTO such as a coal generator can serve load in other pa rts of the RTO, as well as load outside of the RTO. As we cons ider each of these geographic areas in the Geographic Availabili ty TSD, we make key points as to why this final rule does not negatively impact the ability of these regions to access new c oal generation to the extent that coal is needed to sup ply demand and/or those regions want to include new coal-fired generation in their resource mix.

N . Final Requirements for Disposition of Captured CO 2 This section discusses the different regulatory com ponents, already in place, that assure the safety and effect iveness of GS. This section, by demonstrating that GS is alrea dy covered by an effective regulatory structure, complements the analysis of the technical feasibility of GS contained in Sec. V .M. Together, these sections affirm that the technical feasibilit y of GS is adequately demonstrated.

436 In this discussion, we use the term RTO to indicat e both ISOs and RTOs.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 404 of 854 In 2010, the EPA finalized an effective and coheren t regulatory framework to ensure that CO 2 is safely sequestered -- that is, that CO 2 can be injected and remain securely underground for geologic timeframesthe long-term, secure and sa fe storage of large volumes of CO 2 . The EPA developed these Underground Injection Control (UIC) Class VI well regulations u nder authority of the Safe Drinking Water Act (SDWA) to facilitate injection of CO 2 for GS, while protecting human health and the environment by ensuring the protection of undergrou nd sources of drinking water (USDWs). The Class VI regulations ar e built upon 35 years of federal experience regulating undergrou nd injection wells, and many additional years of state UIC progr am expertise. The EPA and states have decades of UIC experience w ith the Class II program, which provides a regulatory framework f or the protection of USDWs for CO 2 injected for purposes of EOR. In addition, to complement both the Class VI and Cl ass II rules, the EPA used CAA authority to develop air-si de monitoring and reporting requirements for CO 2 capture, underground injection, and geologic sequestration through the Greenhouse Gas Reporting Program (GHGRP).GHGRP. Information collected under the GHGRP provides a transparent means for the EPA and the public to continue to evaluate the effectiveness of GS. As explained below, these requirements help ensure that sequestered CO 2 will remain in place, and , using SDWA and CAA*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 405 of 854 authorities, provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities . We note the near consensus in the public responses to the Class VI rulemaking that saline and oil and gas reservoirs p rovide ready

means for secure GS of CO 2 . 437 1. Requirements for UIC Class VI and Class II wellsWells Under SDWA, the EPA developed the UIC Program to re gulate the underground injection of fluids in a manner tha t ensures protection of USDWs. UIC regulations establish six different well classes that manage a range of injectates (e.g ., industrial and municipal wastes; fluids associated with oil an d gas activities; solution mining fluids; and CO 2 for geologic sequestration) and which accommodate varying geolog ic, hydrogeological, and other conditions. The standards apply to injection into any type of formation that meets the rule’s rigorous criteria, and so apply not only to injecti on into deep saline formations, but also can apply to injection into unmineable coal seams and other formations. See 75 FR 77256 (Dec. 10, 2010).

437 “Most commenters encouraged the EPA not to automatically exclude any potential injection formations for GS a t this stage of deployment. Commenters suggested, in particular, that there is sufficient technical basis and scientific eviden ce to allow GS in depleted oil and gas reservoirs and in saline formations, noting that there is consensus on how to inject int o these formation types.” 75 FR at 77252 (Dec. 10, 2010).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 406 of 854 The EPA's UIC regulations define the term USDWs to include current and future sources of drinking water and aq uifers that contain a sufficient quantity of ground water to su pply a public water system, where formation fluids either are cur rently being used for human consumption or that contain less tha n 10,000 ppm total dissolved solids. 438 UIC requirements have been in place for over three decades and have been used by the EP A and states to manage hundreds of thousands of injection wells nationwide. a. Class VI requirements

. In 2010, the EPA established a new class of well, C lass VI. Class VI wells are used to inject CO 2 into the subsurface for the purpose of long-term sequestration. See 75 FR 77230 (Dec. 10, 2010). This rule accounts for the unique nature of CO 2 injection for large-scale GS. Specifically, the EPA addressed the unique characteristics of CO 2 injection for GS including the large CO 2 injection volumes anticipated at GS projects, relat ive buoyancy

of CO 2 , its mobility within subsurface geologic formation s, and its corrosivity in the presence of water. The UIC C lass VI rule was developed to facilitate GS and ensure protectio n of USDWs from the particular risks that may be posed by larg e scale CO 2 injection for purposes of long-term GS. The Class V I rule establishes technical requirements for the permitti ng, geologic

438 40 CFR §144.3.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 407 of 854 site characterization, area of review (i.e., the pr oject area) and corrective action, well construction, operation , mechanical integrity testing, monitoring, well plugging, post- injection site care, site closure, and financial responsibili ty for the purpose of protecting USDWs. 439 Notably: Site characterization includes assessment of the ge ologic, hydrogeologic, geochemical, and geomechanical prope rties of a proposed GS site to ensure that Class VI wells are sited in appropriate locations and CO 2 streams are injected into suitable formations with a confining zone or zones free of t ransmissive

439 The Class VI rule rests on a robust technical and scientific foundation, reflecting scientific oversight and pee r review. In developing these Class VI rules, the EPA engaged with the SAB, providing detailed information on key issues r elating to geologic sequestration – including monitoring schem es; methods to predict and verify capacity, injectivity, and ef fectiveness of subsurface CO 2 storage; and characterization and management of risks associated with plume migration and pressure increases in the subsurface. See: http://yosemite.epa.gov/sab/sabproduct.nsf/0/AD09B4 2B75D9E36D852 57704004882CF?OpenDocument. In addition, the EPA de veloped a peer reviewed Vulnerability Evaluation Framework, w hich served as a technical support document for both the Class VI and Subpart RR rules. See: http://www.epa.gov/climatechange/Downloads/ghgemiss ions/VEFTechnical_Document_072408.pdf. In the section 111 ( b) rulemaking here, the SAB Work Group, in a letter endorsed by t he full SAB Committee, found that “while the scientific and tec hnical basis for carbon storage provisions is new and emerging s cience, the agency is using the best available science and has conducted peer review at a level required by agency guidance. ” Memorandum of Jan. 7, 2014, from SAB Work Group Chair to Membe rs of the Chartered SAB and SAB Liaisons, p. 3. The letter wa s subsequently endorsed by the full SAB. Work Group L etter of Jan. 24, 2014, as edited by the full Committee.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 408 of 854 faults or fractures to ensure USDW protection. 440,441 Site characterization is designed to eliminate unaccepta ble sites that may pose risks to USDWs. Generally, injection of CO 2 for GS should occur beneath the lowermost formation contai ning a

USDW. 442 To increase the availability of Class VI sites in geographic areas with very deep USDWs, waivers from the injection depth requirements may be sought where ow ners or operators can demonstrate USDW protection. 443 Owners or operators of Class VI wells must delineat e the project area of review using computational modeling that accounts for the physical and chemical properties o f the injected CO 2 and displaced fluids and is based on an iterative process of available site characterization, monitor ing, and operational data. 444 Within the area of review, owners or operators must identify and evaluate all artificial penetrations to identify those that need corrective action to pr event the

movement of CO 2 or other fluids into or between USDWs. 445,446 Due

440 75 FR 77240 and 75 FR 77247 (December 10, 2010). 441 40 CFR §146.82 and §146.83. Comments indicating th at EPA rules have not considered issues of exposure pathwa ys such as abandoned wells or formation fissures are mistaken. (See, e.g., Comments of UARG, p. 52.) 442 40 CFR §146.81(d). 443 40 CFR §146.95. 444 40 CFR §146.84(a). 445 40 CFR §146.84(c)(1)(3) and §146.90(d)(1). 446 40 CFR §146.81(d) and §146.84.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 409 of 854 to the potentially large size of the area of review for Class VI wells, corrective actions may be conducted on a pha sed basis during the lifetime of the project. 447 Periodic reevaluation of the area of review is required and enables owners o r operators to incorporate previously collected monitoring and operational data to verify that the CO 2 plume and the associated area of elevated pressure are moving as predicted within th e subsurface. 448

Well construction must use materials that can withs tand contact with CO 2 over the operational and post-injection life of the project. 449 These requirements address the unique physical characteristics of CO 2 , including its buoyancy relative to other fluids in the subsurface and its potential corrosiv ity in the presence of water. Requirements for operation of Class VI injection we lls account for the unique conditions that will occur d uring largescale GS including buoyancy, corrosivity, and high sustained pressures over long periods of operation. 450,451

447 40 CFR §146.84(b)(2)(iv). 448 40 CFR §146.84(e)(1). 449 40 CFR §146.86(b). 450 75 FR 77250-52 (December 10, 2010); see also id. a t 77234-35. Commenters were mistaken in asserting (without refe rence to Class VI provisions) that the EPA had ignored issue s relating to CO 2 properties when injected in large volumes in super critical state into geologic formations. 451 40 CFR §146.88.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 410 of 854 Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring pl an for their projects that includes injectate analysis, mechanic al integrity testing, corrosion monitoring, ground water and geo chemical monitoring, pressure fall-off testing, CO 2 plume and pressure front monitoring and tracking, and, at the discreti on of the Class VI director, surface air and/or soil gas moni toring. 452 Owners and operators must periodically review the t esting and monitoring plan to incorporate operational and moni toring data and the most recent area of review reevaluation. 453 Robust monitoring of the CO 2 stream, injection pressures, integrity of the injection well, ground water quality and geoche mistry, and monitoring of the CO 2 plume and position of the pressure front throughout injection will ensure protection of USDW s from endangerment, preserve water quality, and allow for timely detection of any leakage of CO 2 or displaced formation fluids. Although subsurface monitoring is the primary and e ffective means of determining if there are any risks to a US DW, the Class VI rule also authorizes the UIC Program Director to require surface air and/or soil gas monitoring on a site-sp ecific basis. For example, the Class VI Director may require surf ace air/soil

452 40 CFR §146.90. 453 40 CFR §146.90(j).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 411 of 854 gas monitoring of the flux of CO 2 out of the subsurface, with elevation of CO 2 levels above background serving as an indicator of potential leakage and USDW endangerment. 454 Class VI well owners or operators must develop and update a site-specific, comprehensive emergency and remedial response plan that describes actions to be taken (e.g., ceas e injection) to address potential events that may cause endanger ment to a USDW during the construction, operation, and post-i njection site care periods of the project. 455 Financial responsibility demonstrations are require d to ensure that funds will be available for all area of review corrective action, injection well plugging, post-in jection site care, site closure, and emergency and remedial resp onse. 456 Following cessation of injection, the operator must conduct comprehensive post-injection site care activities t o show the position of the CO 2 plume and the associated area of elevated pressure to demonstrate that neither poses an endan germent to

USDWs. 457 The injection well also must be plugged, and follo wing a demonstration of non-endangerment of USDWs by the Class VI

454 40 CFR §146.90(h)(1) and 75 FR at 77259 (Dec. 10, 2010). 455 40 CFR §146.94. 456 40 CFR §146.85. 457 40 CFR §146.93.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 412 of 854 owner or operator, the site must be closed. 458,459 The default duration for the post-injection site care period is 50 years, with flexibility for demonstrating that an alternat ive period is appropriate if it ensures non-endangerment of USDWs

. 460 Following successful closure, the facility property deed must record that the underlying land is used for GS. 461

The EPA has completed technical guidance documents on Class VI well site characterization, area of review and corrective action, well testing and monitoring, pro ject plan development, well construction, and financial responsibility. 462,463,464,465,466,467 The EPA has also prepared and

458 40 CFR §146.92. 459 40 CFR §146.93. 460 40 CFR §146.93(b). 461 40 CFR §146.93(c). 462 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 3004.pdf. 463 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 3005.pdf. 464 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 3001.pdf. 465 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 1017.pdf. 466 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 1020.pdf. 467 http://water.epa.gov/type/groundwater/uic/class6/up load/uicfinan cialresponsibilityguidancefinal072011v.pdf.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 413 of 854 made available for public comment draftissued guidance documents on transitioning Class II wells to Class VI wells; well plugging, post-injection site care, and site closur e; and recordkeeping, reporting, and data management. 468,469,470,471 To inform the development of the UIC Class VI rule, the EPA solicited stakeholder input and reviewed ongoing do mestic and international GS research, demonstration, and deplo yment projects. The EPA also leveraged injection experien ce of the UIC Program, such as injection via Class II wells for E OR. A description of the work conducted by the EPA in sup port of the UIC Class VI rule can be found in the preamble for the final rule (see 75 FR 77230 and 77237-240 ; ( December 10, 2010 ).)). The EPA has issued Class VI permits for six wells u nder two projects. In September 2014, a UIC Class VI injecti on well

468 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3004.pdf. See also 40 CFR §144.19 and “Key Principles in EPA’s Underground Injection Control Program Class VI Rule Related to Transition of Class II Enhanced Oil Recovery or Gas Recovery Wells to Class VI”, April 23, 2015, Available at: http://water.epa.gov/type/groundwater/uic/class6/up load/class2eo rclass6memo.pdf

. 469 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3005.pdf. 470 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3001.pdf. 471 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3002.pdf.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 414 of 854 permit (to construct) was issued by the EPA to Arch er Daniels Midland for an ethanol facility in Decatur, Illinoi s. The goal of the project is to demonstrate the ability of the Mount Simon geologic formation, a deep saline formation, to acc ept and retain industrial scale volumes of CO 2 for permanent GS. The permitted well has a projected operational period o f five years, during which time 5.5 million metric tons of CO 2 will be injected into an area of review with a radius of approximate ly 2 miles. 472 Following the operational period, Archer Daniels Mi dland plans a post-injection site care period of ten years. 473 In September 2014, the EPA also issued four Class VI injection w ell permits (to construct) to the FutureGen Industrial Alliance project in Jacksonville, Illinois, which proposed to capture C O 2 emissions from a coal-fired power plant in Meredosia, Illinoi s and transport the CO 2 by pipeline approximately 30 miles to the deep saline GS site. 474 The Alliance proposed to inject a total of 22 million metric tons of CO 2 into an area of review with a radius

472 http://www.epa.gov/region5/water/uic/adm/. In addi tion, Archer Daniels Midland received a UIC Class VI inje ction well permit for a second well in December 2014. Archer D aniels Midland had been injecting CO 2 at this well since 2011 under a UIC Class I permit issued by the Illinois EPA. 473 http://www.epa.gov/region5/water/uic/adm/. 474 After permit issuance, and for reasons unrelated t o the permitting proceeding, DOE initiated a structured c loseout of federal support for the FutureGen project in Februa ry 2015. However, these are still active Class VI permits.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 415 of 854 of approximately 24 miles over the 20 year life of the project, with a post-injection site care period of fifty yea rs. 475 Both permit applicants addressed siting and operati onal aspects of GS (including issues relating to volumes of the CO 2 and nature of the CO 2 injectate), and included monitoring that helps provide assurance that CO 2 will not migrate to shallower formations. The permits were based on findings that regional and local features at the site allow the site to receiv e injected CO 2 in specified amounts without buildup of pressure wh ich would create faults or fractures, and further, that monit oring provides early warning of any changes to groundwate r or CO 2 leakage. 476 The permitting of these projects illustrates that p ermit applicants were able to address perceived challenge s to issuance of Class VI permits. These permits demonstrate the EPA’s view that these projects are capable of safely and secur ely sequestering large volumes of CO 2 --- including from steam generating units

--- for geologic timeframeslong-term storage since the EPA would not otherwise have issued the p ermits.

475 http://www.epa.gov/r5water/uic/futuregen/. 476 http://www.epa.gov/r5water/uic/futuregen/; http://www.epa.gov/region5/water/uic/adm/.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 416 of 854 b. Class II requirements

. As explained in section K.2Section M.3 above, CO 2 has been injected into the subsurface via injection wells fo r EOR, boosting production efficiency by re-pressurizing o il and gas reservoirs and increasing the mobility of oil. Ther e are decades of industry experience in operating EOR projects. T he

CO 2 injection wells used for EOR are regulated through the UIC Class II program. 477 CO 2 storage associated with Class II wells is

a common occurrence and CO 2 can be safely stored where injected through Class II-permitted wells for the purpose of enhanced oil or gas-related recovery. UIC Class II regulations issued under section 1421 of SDWA provide minimum federal requirements for site chara cterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectat e sampling, mechanical integrity testing, plugging and abandonm ent, financial responsibility, and reporting. Class II w ells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that c ould lead to loss of injectate and migration into USDWs. Section 1425 of SDWA allows states to demonstrate t hat their program is effective in preventing endangerme nt of USDWs.

477 40 CFR §144.6(b).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 417 of 854 These programs must include permitting, inspection, monitoring, record-keeping, and reporting components. 2. Relevant requirementsRequirements of the Greenhouse Gas Reporting Program ( GHGRP ) The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and s uppliers in the United States. The final rules under 40 CFR par t 60 specifically require that if an affected EGU captur es CO 2 to meet the applicable emissions limit, the EGU must report in accordance with 40 CFR part 98, subpart PP (Supplie rs of Carbon Dioxide) and the captured CO 2 must be injected at a facility or facilities that reports in accordance with 40 CFR p art 98, subpart RR (Geologic Sequestration of Carbon Dioxid e). See 40 CFR 60.46Da(h)(5) and 40 CFR § 60.5555( df ). Taken together, these requirements ensure that the amount of captured and sequestered

CO 2 will be tracked as appropriate at project- and nat ionallevels, and that the status of the CO 2 in its sequestration site will be monitored, including air-side monitoring an d reporting. Specifically, subpart PP provides requirements to a ccount for CO 2 supplied to the economy. This subpart requires aff ected facilities with production process units that captu re a CO 2 stream for purposes of supplying CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground to rep ort the mass*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 418 of 854

of CO 2 captured and supplied to the economy. 478 CO 2 suppliers are required to report the annual quantity of CO 2 transferred offsite and its end use, including GS. 479 This rule finalizes amendments to subpart PP report ing requirements, specifically requiring that the follo wing pieces of information be reported: (1) the electronic GHG Reporting Tool identification (e-GGRT ID) of the EGU facility from which

CO 2 was captured, and (2) the e-GGRT ID(s) for, and ma ss of CO 2 transferred to, each GS site reporting under subpar t RR. 480 As noted, this final rule also requires that any af fected EGU unit that captures CO 2 to meet the applicable emissions limit must transfer the captured CO 2 to a facility that reports under GHGRP subpart RR. In order to provide clarity on th is requirement, the EPA reworded the proposed language under 40 CFR 60.46Da(h)(5) and 40 CFR § 60.5555( df ) to use the phrase “If your affected unit captures CO 2 ” in place of the phrases “If your affected unit uses geologic sequestration” andphras e “If your affected unit employs geologic sequestration ”, respectively.”. This revision is not a change from the EPA’s initia l intent. Reporting under subpart RR is required for all faci lities that have received a Class VI UIC permit for inject ion of CO 2 . 481

478 40 CFR §98.420(a)(1). 479 40 CFR §98.426. 480 40 CFR §98.426(h). 481 40 CFR §98.440.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 419 of 854 Subpart RR requires facilities meeting the source c ategory definition (40 CFR 98.440) for any well or group of wells to report basic information on the mass of CO 2 received for injection; develop and implement an EPA-approved mo nitoring, reporting, and verification (MRV) plan; report the mass of CO 2 sequestered using a mass balance approach; and repo rt annual monitoring activities. 482,483,484,485 Although deep subsurface monitoring is the primary and effective means of de termining if there are any leaks to a USDW, the monitoring emplo yed under a subpart RR MRV Plan can be utilized, if required by the UIC Program Director, to further ensure protection of U SDWs. 486 The subpart RR MRV plan includes five major components: A delineation of monitoring areas based on the CO 2 plume location. Monitoring may be phased in over time. 487 An identification and evaluation of the potential s urface leakage pathways and an assessment of the likelihoo d, magnitude, and timing, of surface leakage of CO 2 through these pathways. The monitoring program will be designed to address the risks identified. 488

482 40 CFR §98.446. 483 40 CFR §98.448. 484 40 CFR §98.446(f)(9) and (10). 485 40 CFR §98.446(f)(12). 486 See 75 FR at 77263 (Dec. 10, 2010). 487 40 CFR §98.448(a)(1). 488 40 CFR §98.448(a)(2).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 420 of 854 A strategy for detecting and quantifying any surfac e leakage of CO 2 in the event leakage occurs. Multiple monitoring methods and accounting techniques can be used to ad dress changes in plume size and risks over time. 489 An approach for establishing the expected baselines for monitoring CO 2 surface leakage. Baseline data represent preinjection site conditions and are used to identify potential anomalies in monitoring data. 490 A summary of considerations made to calculate site- specific variables for the mass balance equation. Site-speci fic variables may include calculating CO 2 emissions from equipment leaks and vented emissions of CO 2 from surface equipment, and considerations for calculating CO 2 from produced fluids. 491 Subpart RR provides a nationally consistent mass ba lance framework for reporting the mass of CO 2 that is sequestered. Certain monitoring and operational data for a GS si te is required to be reported to the EPA annually. More i nformation on the MRV plan and annual reporting is available in t he subpart RR final rule (75 FR 75065; December 1, 2010) and its associated technical support document. 492

489 40 CFR §98.448(a)(3). 490 40 CFR §98.448(a)(4). 491 40 CFR §98.448(a)(5). 492 Technical Support Document: “General Technical Sup port Document for Injection and Geologic Sequestration o f Carbon*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 421 of 854 Under this final rule, any well receiving CO 2 captured from

an affected sourceEGU , be it a Class VI or Class II well, must report under subpart RR. 493 As explained below in Section

LV.N .5.a, a Class II well’s UIC regulatory status does not change because it receives such CO 2 . Nor does it change by virtue of reporting under subpart RR. 3. UIC and GHGRP rules provide assuranceRules Provide Assurance

to prevent, monitorPrevent, Monitor , and address releasesAddress

Releases of sequesteredSequestered CO 2 to airAir Together the requirements of the UIC and GHGRP prog rams help ensure that sequestered CO 2 will remain secure, and provide the monitoring mechanisms to identify and address p otential leakage using SDWA and CAA authorities. The EPA des igned the GHGRP subpart RR requirements for GS with considera tion of UIC requirements. The monitoring required by GHGRP subp art RR is complementary to and builds on UIC monitoring and t esting requirements. 75 FR 77263. Although the regulations for Class VI and Class II injection wells are designed to ensure protection of USDWs from endangerment , as explained below, the practical effect of these complementary technical requirement s , as

Dioxide: Subparts RR and UU” (Docket EPA–HQ–OAR–200 9–0926), November 2010. 493 See §60. 46Da(h)(5) and §60. 5555( df ).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 422 of 854 explained below, is that they also prevent releases of CO 2 to the atmosphere. The UIC and GHGRP programs are built upon an unders tanding of the mechanisms by which CO 2 is retained in geologic formations, which are well understood and proven. Structural and stratigraphic trapping is a physical trapping mechanism that occurs when the CO 2 reaches a stratigraphic zone with low permeability (i.e., geo logic confining system) that prevents further upward migr ation. Residual trapping is a physical trapping mechanism that occurs as residual CO 2 is immobilized in formation pore spaces as disconnected droplets or bubbles at the trailing ed ge of the plume due to capillary forces. Adsorption trapping is another physical trapping me chanism

that occurs when CO 2 molecules attach to the surfaces of coal and certain organic rich shales, displacing other molec ules such as

methane. Solubility trapping is a geochemical trapping mecha nism where a portion of the CO 2 from the pure fluid phase dissolves into native ground water and hydrocarbons. Mineral trapping is a geochemical trapping mechanis m that occurs when chemical reactions between the dissolve d CO 2 and minerals in the formation lead to the precipitation of solid carbonate minerals.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 423 of 854

a. Class VI Wells. wells As just discussed in section LSection V.N .1, the UIC Class VI rule provides a framework to ensure the safety o f underground injection of CO 2 such that USDWs are not endangered. As explained below, protection against releases to USDWs likewis e assures against releases to ambient air. Through the injection well permit application process, the Class VI permit app licant (i.e., a prospective Class VI well owner or operator) must demonstrate that the injected CO 2 will be trapped and retained in the geologic formation, and not migrate out of the inje ction zone or the approved project area (i.e., the area of review ). To assure

that CO 2 is confined within the injection zone, major compo nents to be considered and included in Class VI permits a re site characterization, area of review delineation and co rrective action, well construction and operation, testing an d monitoring, financial responsibility, post-injection site care, well plugging, emergency and remedial response, and site closure as described in Section LV.N .1. Site characterization provides the foundation for successful GS projects. It includes evaluation of t he chemical and physical mechanisms that will occur in the subs urface to immobilize and securely store the CO 2 within the injection zone for geologic timeframesover the long-term (see above). Site characterization requires a detailed assessment of the geologic,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 424 of 854 hydrogeologic, geochemical, and geomechanical prope rties of the proposed GS site to ensure that wells are sited in suitable locations. 494 Data and information collected during site characterization are used in the development of inj ection well construction and operating plans; provide inputs fo r modeling the extent of the injected CO 2 plume and related pressure front; and establish baseline information to which geochem ical, geophysical, and hydrogeologic site monitoring data collected over the life of the injection project can be compa red. The Class VI rules contain rigorous subsurface moni toring requirements to assure that the chosen site is func tioning as characterized. This subsurface monitoring should de tect leakage

of CO 2 before CO 2 would reach the atmosphere. For example, when USDWs are present, they are generally located above the injection zone. If CO 2 were to reach a USDW prior to being released to the atmosphere, the presence of CO 2 or geochemical changes that would be caused by CO 2 migration into unauthorized zones would be detected by a UIC Class VI monitorin g program that is approved and periodically evaluated/adjuste d based on permit conditions. Likewise, UIC Class VI mechanical integrity testing requirements are designed to confirm that a well ma intains

494 40 CFR §146.82(a) and (c).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 425 of 854 internal and external mechanical integrity. Continu ous monitoring of the internal mechanical integrity of Class VI wells ensures that injection wells maintain integri ty and serves as a way to detect problems with the well system. M echanical integrity testing provides an early indication of p otential issues that could lead to CO 2 leakage from the confining zone, providing assurance and verification that CO 2 will not reach the atmosphere. Further assurance is provided by the regulatory req uirement that injection must cease if there is evidence that the injected

CO 2 and/or associated pressure front may cause endange rment to a

USDW. 495 Once the anomalous operating conditions are verifi ed, the cessation of injection, as required by UIC perm its, will minimize any risk of release to air. Following cessation of injection, the operator must conduct comprehensive post-injection site care to show the position of

the CO 2 plume and the associated area of elevated pressure to demonstrate that neither poses an endangerment to U SDWs – also having the practical effect of preventing releases of CO 2 to the atmosphere. Post-injection site care includes appro priate monitoring and other needed actions (including corr ective action). The default duration for the post-injectio n site care

495 40 CFR § 146.94(b )).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 426 of 854 period is 50 years, with flexibility for demonstrat ing that an alternative period is appropriate if it ensures non -endangerment

of USDWs. As the EPA has found, “[ the ] UIC Class VI injection well requirements , which protect against releases from all exposure pathways. Specifically, the EPA stated that the Cla ss VI rules “[ are ] specifically designed to ensure that the CO 2 ( and any incidental associated substances derived from the s ource materials and the capture process) will be isolated within the injection zone. The EPA concluded that the eliminat ion of exposure routes through these requirements, which a re implemented through a SDWA UIC permit, will ensure protection of human health and the environment ...”...”. 496 GHGRP subpart RR complements these UIC Class VI requirements. Requirements under the UIC program ar e focused on demonstrating that USDWs are not endangered as a re sult of CO 2 injection into the subsurface, while requirements u nder the GHGRP through subpart RR enable accounting for CO 2 that is geologically sequestered. A methodology to account for potential leakage is developed as part of the subpart RR MRV plan (see Section LV.N .2). The MRV plan submitted for subpart RR may

496 79 FR at 353 (January 3, 20152014 ) (Final Hazardous Waste Management System: Conditional Exclusion forCarbonfor Carbon Dioxide (CO 2 ) Streams in Geologic Sequestration Activities unde r subtitle C of RCRA). See Section LN .5.c below.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 427 of 854 describe (or provide by reference to the UIC permit ) the relevant elements of the UIC permit (e.g. assessmen t of leakage pathways in the monitoring area) and how those elem ents satisfy the subpart RR requirements. The MRV plan required under subpart RR may rely upon the knowledge of the subsurface lo cation of CO 2 and site characteristics that are developed in the permit application process, and operational monitoring res ults for UIC Class VI permitted wells. In summary, there are well-recognized physical mech anisms for storing CO 2 securely. The comprehensive and rigorous site characterization requirements of the Class VI rules assure that sites with these properties are selected. Subsurfac e monitoring serves to assure that the sequestration site operat es as intended, and this monitoring continues through a p ost-closure period. Although release of CO 2 to air is unlikely and should be detected prior to release by subsurface monitoring, the subpart RR air-side monitoring and reporting regime provide s backup assurance that sequestered CO 2 has not been released to the atmosphere.

b. Class II wells

. The Class II rules likewise are designed to protect USDWs during EOR operation, including the injection of CO 2 for EOR. For example, UIC Class II minimum federal requirements promulgated under SDWA address site characterization, area of r eview, well*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 428 of 854 construction (e.g., casing and cementing), well ope ration (e.g., injection pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial respon sibility, and reporting. Class II wells must undergo periodic mec hanical integrity testing which will detect well constructi on and operational conditions that could lead to loss of i njectate and migration into USDWs. The establishment of maximum injection pressures, designed to ensure that the pressure in the injection zone during injection does not initiate new fractur es or propagate existing fractures in the confining zone , prevents injection from causing the movement of fluids into an underground source of drinking water. The safeguard s that protect USDWs also serve as an early warning mechan ism for

releases of CO 2 to airthe atmosphere

. CO 2 injected via Class II wells becomes sequestered by the trapping mechanisms described above in this Section LV.N .3. a. As with Class VI wells, for Class II wells that report under subpart RR, there is monitoring to evaluate whether CO 2 used for EOR will remain safely in place both during and aft er the injection period. Subpart RR provides a CO 2 accounting framework that will enable the EPA to assess both the project-level and national efficacy of geologic sequestration to dete rmine whether additional requirements are necessary and, if so, i nform the design of such regulations.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 429 of 854

c. Response to Comments. comments Commenters maintained that GS was not demonstrated for CO 2 captured from EGUs. In addition, commenters noted t hat the volumes of captured CO 2 would be considerably larger than from existing GS sites, and could quadruple amounts inje cted into Class II EOR wells. In addition to volumes of CO 2 to be injected, commenters opined on the possibility of sporadic CO 2 supply due to the nature of EGU operation. 497 The EPA does not agree. CO 2 capture from EGUs is demonstrated as discussed in Sections V.D and V.E. As discussed below, the volumes of CO 2 are comparable to the amounts that have been injected at large scale commercial operations. The EPA also disagrees that the volume of CO 2 would quadruple amounts injected into Class II EOR wells because CO 2 may be sequestered in deep saline formations, which have widespread geographic availability (see Section JM .1). The BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. 498 However, the EPA also recognizes the potential for sequestering

CO 2 via EOR and allows the use of EOR as a compliance option.

497 See, e.g. Comments of Southern Company, p. 41. 498 The EPA anticipates EOR projects may be early GS p rojects because these formations have been previously well characterized for hydrocarbon recovery, likely already have suita ble infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of oil production.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 430 of 854 According to data reported to the GHGRP, approximat ely 60 million metric tons of CO 2 were supplied to EOR in the United States in 2013. 499 Approximately 70 percent of total CO 2 supplied in the United States was produced from geologic (na tural) CO 2 sources and approximately 30 percent was captured f rom anthropogenic sources. CO 2 pipeline systems, such as those serving the Permian Basin, have multiple sources of CO 2 that serve to levelize the pipeline supply , thus minimizing the effect of supply on the EOR operator. GS of anthropogenic CO 2 in deep saline formations is demonstrated. First, as explained above, the EPA ha s issued construction permits under the Class VI program. It would not have done so, and under the regulations cannot have done so, without demonstrations that CO 2 would be securely confined. One of these projects was for a steam generating EGU. Second, international experience with large scale commercial GS projects has demonstrated through ext ensive monitoring programs that large volumes of CO 2 can be safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected un der this rule. This experience has also demonstrated the val ue and efficacy of monitoring programs to determine the lo cation of CO 2

499 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 431 of 854 in the subsurface and detect potential leakage thro ugh the presence of CO 2 in the shallow subsurface, near surface and air. The Sleipner CO 2 Storage Project is located at an offshore gas field in the North Sea where CO 2 must be removed from the natural gas in order to meet customer requirements and reduce costs. The project began injecting CO 2 into the deep subsurface in 1996. The single offshore injection well injects approximately 1 million metric tons per year into a thick, permeable sandstone above the gas producing zone. A pproximately 15 million metric tons of CO 2 have been injected since inception. Many US and international organizations have conduc ted monitoring at Sleipner. The location and dimensions of the CO 2 plume have been measured numerous times using 3-dim ensional seismic monitoring since the 1994 pre-injection sur vey. The monitoring data have demonstrated that although the plume is behaving differently than initially modeled due to thin layers of impermeable shale that were not initially identi fied in the reservoir model, the CO 2 remains trapped in the injection zone. Numerous other techniques have been successfully us ed to monitor

CO 2 storage at Sleipner. The research and monitoring a t Sleipner demonstrates the value of a comprehensive approach to site characterization, computational modeling and monito ring, as is required under UIC Class VI rules. The experience a t Sleipner demonstrates that large volumes of CO 2 , of the same order of*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 432 of 854 magnitude expected for an EGU, can be safely inject ed and stored in saline reservoirs over an extended period. Snøhvit is another large offshore CO 2 storage project, located at a gas field in the Barents Sea. Like Sle ipner the natural gas must be treated to reduce high levels o f CO 2 to meet processing standards and reduce costs. Gas is trans ported via pipeline 95 miles to a gas processing and liquefied natural gas plant and the CO 2 is piped back offshore for injection. Approximately 0.7 million metric tons per year CO 2 are injected into permeable sandstone below the gas reservoir. B etween 2008 and 2011, the operator observed pressure increases in the injection formation (Tubaen Formation) greater than expected and conducted time lapse seismic surveys and studies of the injection zone and concluded that the pressure incr ease was mainly caused by a limited storage capacity in the formation. 500 In 2011, the injection well was modified and inject ion was initiated in a second interval (Stø Formation) in t he field to increase the storage capacity. Approximately 3 mill ion metric

tons of CO 2 have been injected since 2008. Monitoring

500 Grude, S. M. Landrøa, and J. Dvorkinb, 2014, Press ure effects caused by CO 2 injection in the Tubåen Fm., the Snøhvit field. International Journal of Greenhouse Gas Control 27 (2014) 178– 187. Commenters argued that the project had failed to sequester CO 2 , referring to the initial cessation of injection. See, e.g. Comments of UARG p. 56. In fact, injection resumed successfully, as described in the text above.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 433 of 854 demonstrates that no leakage has occurred, again de monstrating that large volumes of CO 2 , of the same order of magnitude expected for an EGU, can be safely injected and sto red in deep saline formations over an extended period. As discussed above in Section KSections V.E.2.a and M , CO 2 from the Great Plains Synfuels plant in North Dakot a has been injected into the Weyburn oil field in Saskatchewan Canada since 2000. Over that time period the project has injecte d more than 16 million metric tons of CO 2 . It is anticipated that approximately 40 million metric tons of CO 2 will be permanently sequestered over the lifespan of the project. Exten sive monitoring by U.S. and international partners has d emonstrated that no leakage has occurred. The sources of CO 2 for EOR may vary (e.g., industrial processes, power generation ),); however , this does not impact the effectiveness of EOR operations (see Section K.2V.M.3 ).

CO 2 used for EOR may come from anthropogenic or natura l

sources. The source of the CO 2 does not impact the effectiveness of the EOR operation. CO 2 capture, treatment and processing steps provide a concentrated stream of CO 2 in order to meet the needs of the intended end use. CO 2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Mat erials Safety Administration found at 49 CFR part 195 (Transporta tion of Hazardous Liquids by Pipeline) apply regardless of the source of*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 434 of 854

the CO 2 and take into account CO 2 composition, impurities, and phase behavior. Additionally, EOR operators and tra nsport companies have specifications to ensure related to the composition of CO 2 . These requirements and specifications ensure EOR operators receive a known and consistent CO 2 stream. At the In Salah CO 2 storage project in Algeria, CO 2 is removed from natural gas produced at three nearby g as fields in order to meet export quality specification. The CO 2 is transported by pipeline approximately 3 miles to th e injection site. Three horizontal wells are used to inject the CO 2 into the down-dip aquifer leg of the gas reservoir approxima tely 6,200 feet deep. Between 2004 and 2011 over 3.8 million m etric tons of

CO 2 were stored. Injection rates in 2010 and 2011 were approximately 1 million metric tons per year. Storage integrity has been monitored by several US and international organizations and the monitoring program has employed a wide rang e of geophysical and geochemical methods, including time lapse seismic, microseismic, wellhead sampling, tracers, down-hole logging, core analysis, surface gas monitoring, gro undwater aquifer monitoring and satellite data. The data hav e been used to support periodic risk assessments during the ope rational phase of the project. In 2010 new data from seismic , satellite and geomechanical models were used to inform the ri sk assessment and led to the decision to reduce CO 2 injection pressures due to*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 435 of 854 risk of vertical leakage into the lower caprock, an d risk of loss of well integrity. The caprock at the site con sisted of main caprock units, providing the primary seal, and lower caprock units, providing additional buffers. There was no leakage from the well or through the caprock, but t he risk analysis identified an increased risk of leakage, t herefore, the aforementioned precautions were taken. Additional a nalysis of the reservoir, seismic and geomechanical data led t o the decision to suspend CO 2 injection in June 2011. No leakage has occurred and the injected CO 2 remains safely stored in the subsurface. The decision to proceed with safe shutd own of injection resulted from the analysis of seismic and geomechanical data to identify and respond to stora ge site risk. The In Salah project demonstrates the value of deve loping an integrated and comprehensive set of baseline site d ata prior to the start of injection, and the importance of regul ar review of monitoring data. Commenters also noted that the dat a collection and analysis had proven effective at preventing any release of sequestered CO 2 to either underground drinking water sources or

to the ambient airatmosphere

. 501

501 “It is important to note that although the In Sala h project is no longer injecting CO 2 , the CCS community still views this early saline project as a success because the monit oring program served its intended purpose. That is, the monitorin g methods deployed at this site informed the operator of a po tential*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 436 of 854 These projects demonstrate that sequestration of CO 2 captured from industrial operations has been succes sfully conducted on a large scale and over relatively long periods of time. The volumes of captured CO 2 are within the same order of magnitude as that expected from EGUs. Even though p otentially adverse conditions were identified at some projects (In Salah and Snøhvit), there were no releases to air and the monitoring systems were effective in identifying the issues in a timely manner, and these issues were addressed effectively . In each case, the site-specific characteristics were evalua ted on a case-by-case basis to select a site where the geolo gic conditions are suitable to ensure long-term, safe s torage of CO 2 . Each project was designed to address the site-speci fic characteristics and operated to successfully inject CO 2 for safe storage. 54 . Must the standard of performance for CO 2 include CAA requirements on the sequestration site? One commenter maintained as a matter of law that a standard predicated on use of CCS is not a “system of emissi on reduction”, and therefore is not a “standard of per formance” within the meaning of section 111 (a)(1) of the Act . The commenter argued that the standard does not require

problem, leading to a shutdown of CO 2 injection before the Caprock was breached.” Comment of EPRI, p. 14.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 437 of 854 sequestration of captured CO 2 but only capture, so that no emission reductions are associated with the standar d. A gloss on this argument is that there are no enforceable requ irements for the captured CO 2 (“[t]he fate of that [captured] CO 2 is something that the proposed standard does not proscribe with enforceable requirements”). The commenter further argues that a “system of emission reduction” under section 111 must be “desi gned into the

new source itself ” so that off-site underground sequestration of captured CO 2 emissions “could never satisfy the statutory requirements governing a ‘standard of performance’” (emphasis original). 502 The EPA disagrees with both the legal and factual assertions in this comment. As to the legal point, the commenter fails to distinguish capture and sequestration of c arbon from every other section 111 standard which is predicate d on capture of a pollutant. Indeed, all emission standards not predicated on outright pollutant destruction involve capture of t he pollutant and its subsequent disposition in the capturing med ium. Thus, metals are captured in devices like baghouses or sc rubbers, leaving a solid waste or wastewater to be managed. Gases can be captured with activated carbon , or under pressure, again requiring further management of the captured pollut ant(s). The

502 Comments of UARG, pp. 37 , - 38.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 438 of 854 EPA is required to consider these potential implica tions in promulgating an NSPS. See section 111 (a)(1) (in promulgating a standard of performance under section 111, the EPA must “tak[e] into account ... any nonair quality health and enviro nmental impact”). The EPA thus considers such issues as sol id waste and wastewater generation as part of determining if a s ystem of emission reduction is “best” and “adequately demonstrated” under section 111. See Section V.O below (discussion of this rule’s potential cross-media impacts). The further comment that the standard is arbitrary because it fails to impose any requirements on the captured CO 2 is misplaced. The commenter mischaracterizes the stand ard as requiring capture only. The BSER is not just captur ing a certain

amount of CO 2 , but sequestering it. Sequestration can occur either on-site or off-site. Sequestration sites rec eiving and injecting the captured CO 2 are required to obtain UIC permits and report under subpart RR of the GHGRP. They must con duct comprehensive monitoring as part of these obligatio ns. Although the NSPS does not impose regulatory requirements on the transportation pipeline or the sequestration site, such requirements already exist under other regulatory p rograms of the Department of Transportation and the EPA. In pa rticular, the EPA is reasonably relying on the already-adopted, a nd very rigorous, Class VI well requirements in combination with the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 439 of 854 subpart RR requirements to provide secure sequestra tion of captured CO 2 . The EPA has also considered carefully the requirements and operating history of the Class II requirements for EOR wells, which, in combination with the subpa rt RR requirements, ensure protection of USDWs from endan germent, provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities, a nd have the practical effect of preventing releases of CO 2 to the atmosphere. This is analogous to the many section 111 standards of performance for metals which result in a captured a ir pollution control residue to be disposed of pursuant to waste management requirements of the rules implementing the Resource Conservation and Recovery Act , and. It is also analogous to the many section 111 standards of performance for metals or organics captured in wet air pollution control systems resulting in wast ewater discharged to a navigable water where pollutant loa dings are controlled under rules implementing the Clean Water Act. Again, these are non-air environmental impacts for which t he EPA must account in establishing a section 111(a) standard. The EPA has reasonably done so here based on the regulatory reg imes of the Class VI and Class II UIC requirements in combinati on with the monitoring regime of the subpart RR reporting rules , as well as

the CO 2 pipeline standards of the Department of Transporta tion.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 440 of 854 In this regard, the EPA notes that at proposal it acknowledged the possibility “that there can be dow nstream losses of CO 2 after capture, for example during transportation, injection or storage.” 79 FR at 1484. Given the rig orous substantive requirements and the monitoring require d by the Class VI rules, the complementary monitoring regime of the subpart RR MRV plan and reporting rules, as well as the regulatory requirements for Class II wells, any suc h losses would be de minimis. Indeed, the same commenter mai ntained that the monitoring requirements of the Class VI rule ar e overly stringent and that a 50-year post-injection site ca re period is unnecessarily long. 503 As it happens, as noted above, the Class VI rules allow for an alternative post-injection si te care period based on a site-specific demonstration. See 40 CFR 146.93(b).

The EPA addresses these commentsthis comment in more detail in Chapter 2 of the Response - to - Comment Document. 65 . Other Perceived Obstacles to Geologic Sequestrati on a. Class II to Class VI transition

. A number of commenters maintained that the Class VI rules could effectively force all Class II wells to trans ition to Class VI wells if they inject anthropogenic CO 2 , and further

503 Comments of UARG, p. 63.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 441 of 854 maintained that, as a practical matter, this would render EOR unavailable for such CO 2 . The EPA disagrees with these comments. Injection of anthropogenic CO 2 into Class II wells does not force transition of these wells to Class VI wells – not d uring the well’s active operation and not when EOR operations cease. We recognize the widespread use of EOR and the expecta tion that injected CO 2 can remain underground. The EPA issued a memorandu m to its regional offices on April 23, 2015 reflectin g these principles: 504 Geologic storage of CO 2 can continue to be permitted under the UIC Class II program. Use of anthropogenic CO 2 in EOR operations does not necessitate a Class VI permit. Class VI site closure requirements are not required for

Class II CO 2 injection operations. EOR operations that are focused on oil or gas produ ction will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Cla ss II permitted EOR operation, the key factor in determin ing the

504 “Key Principles in EPA’s Underground Injection Con trol Program Class VI Rule Related to Transition of Clas s II Enhanced Oil Recovery or Gas Recovery Wells to Class VI”, Ap ril 23, 2015. Available at: http://water.epa.gov/type/groundwater/uic/class6/up load/class2eo rclass6memo.pdf

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Page 442 of 854 potential need to transition aan EOR operation from Class II to Class VI is increased risk to USDWs related to sign ificant storage of CO 2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. 505 b. GHGRP Subpart RR

. A number of commenters maintained that no EOR opera tor would accept captured carbon from an EGU due to the reporting and other regulatory burdens imposed by the monitor ing requirements of GHGRP subpart RR. 506 They noted that preparing a subpart RR MRV plan could cost upwards of $100,000 which would be cost prohibitive given other available sources o f CO 2 . The EPA disagrees with this comment in several resp ects. First, the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, n ot on EOR. However, the EPA also recognizes the potential for sequestering

CO 2 via EOR, but disagrees that subpart RR is prohibitive torequirements effectively preclude or substantiall y inhibit the

use of EOR.

505 In this regard, the Class VI rules provide that, “ [o]wners or operators that are injecting carbon dioxide for the primary purpose of long-term storage into an oil and gas re servoir must apply for and obtain a Class VI geologic sequestrat ion permit when there is an increased risk to USDWs compared t o Class II operations.” 40 CFR §144.19. 506 See e.g., comments of UARG, p, 63; Southern , Co., p. 37; American Petroleum Institute pp. 40-50.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 443 of 854 The cost of compliance with subpart RR is not signi ficant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR ar e relatively modest, especially in comparison with revenues from an EOR field. In the economic impact analysis for subpart RR, the EPA estimated that an EOR project with a Class II permi t would incur a first year cost of up to $147,030 to develop an M RV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262

per year. 507 Monitoring costs are estimated to range from $0.02 per metric ton (base case scenario) to approximatel y $2 per metric ton of CO 2 (high scenario). Using a range of scenarios (that included high end estimates), these subpart R R costs are approximately three to four percent of estimated re venues for an average EOR field, indicating that the costs can re adily be absorbed. 75 FR 75073. Furthermore, there is a demand for new CO 2 by EOR operators, even beyond current natural sources of CO 2. For example, in an April 2014 study, DOE concluded that future develop ment of EOR will need to rely on captured CO 2 . 508 Thus, the argument that EOR

507 Subpart RR costs are presented in 2008 US dollars. 508 “Near Term Projections of CO 2 Utilization for Enhanced Oil Recovery”. DOE/NETL-2014/1648. April 2014.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 444 of 854 operators will obtain CO 2 from other sources without triggering subpart RR responsibilities, which assumes adequate supplies of

CO 2 from other sources, lacks foundation. In addition, the Internal Revenue Code section 45Q provides a tax cr edit for CO 2 sequestration which is far greater than subpart RR costs. 509 In sum, the cost of complying with subpart RR requirem ents, including the cost of MRV, is not significant enoug h to deter EOR operators from purchasing EGU captured CO 2 . The EPA addresses these comments in more detail in the Response to Comment Document. c. Conditional exclusion for geologic sequestration of CO2 streams under the Resource Conservation and Recover y Act (RCRA ). ) Certain commenters voiced concerns that regulatory requirements for hazardous wastes might apply to ca ptured CO 2 and these requirements might be inconsistent with, or o therwise impede, GS of captured CO 2 from EGUs. The EPA has acted to remove any such (highly conjectural) uncertainty. The Reso urce Conservation and Recovery Act (RCRA) authorizes the EPA to regulate the management of hazardous wastes. In par ticular, RCRA

509 http://www.irs.gov/irb/2009-44_IRB/ar11.html. The section 45Q tax credit for calendar year 2014 was2015 is $10. 7592 per metric ton of qualified CO 2 that is captured and used in a qualified EOR project and $21. 5185 per metric ton of qualified CO 2 that is capturecaptured and used in a qualified non-EOR GS project. http://www.irs.gov/irb/ 2014-272015-26 _IRB/ ar12ar14 .html.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 445 of 854 Subtitle C authorizes a cradle to grave regulatory program for wastes identified as hazardous, whether specificall y listed as hazardous or whether the waste fails certain tests of hazardous characteristics. The EPA currently has little infor mation to

conclude that CO 2 streams (defined in the RCRA exclusion rule as including incidental associated substances derived from the source materials and the capture process, and any s ubstances added to the stream to enable or improve the inject ion process) might be identified as “hazardous wastes” subject t o RCRA Subtitle C regulation. 510 Nevertheless, to reduce potential uncertainty regarding the regulatory status of CO 2 streams under RCRA Subtitle C, and in order to facilitate the dep loyment of geologic sequestration, the EPA recently concluded a rulemaking to exclude certain CO 2 streams from the RCRA definition of

hazardous waste. 511 In that rulemaking, the EPA determined that if any such CO 2 streams would be hazardous wastes, further RCRA regulation is unnecessary to protect human health a nd the environment provided certain conditions are met. Sp ecifically, the rule conditionally excludes from Subtitle C reg ulations CO 2 streams if they are (1) transported in compliance w ith U.S.

510 No hazardous waste listings apply to CO 2 streams. Therefore, a CO 2 stream could be identified (i.e. defined ) as a hazardous waste only if it exhibits one or more of the hazard ous characteristics. 79 FR 355 (Jan 3. 2014). 511 79 FR 350 (Jan. 3, 2014).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 446 of 854 Department of Transportation or state requirements; (2) injected in compliance with UIC Class VI requirements (summa rized above); (3) no other hazardous wastes are mixed with or co- injected with

the CO 2 stream; and (4) generators (e.g., emission sources ) and Class VI well owners or operators sign certificatio n statements. See 40 CFR 261.4(h)). 512 The D.C. Circuit recently dismissed all challenges to this rule in Carbon Sequestration Council and Southern Company Services v. EPA , No. 787 F. 3d 1129 (D.C Cir. 2015). d. Other perceived uncertainties

. Other commenters claimed that various legal uncerta inties preclude a finding that geologic sequestration of C O 2 from EGUs

512 The EPA made clear in the final conditional exclus ion that that rule does not address, and is not intended to affect the RCRA regulatory status of CO 2 streams that are injected into wells other than Class VI. However, the EPA noted i n the preamble to the final rule that (based on the limit ed information provided in public comments) should CO 2 be used for its intended purpose as it is injected into UIC Cla ss II wells for the purpose of EOR/EGR (enhanced oil recovery / enhanced gas recovery), it is the EPA’s expectation that such an injection process would not generally be a waste management a ctivity. 79 FR 355. The EPA encouraged persons to consult with the appropriate regulatory authority to address any fac t-specific questions that they may have regarding the status o f CO 2 in situations that are beyond the scope of that rule. Id. Moreover, use of anthropogenic CO 2 for EOR is long-standing and has flourished in all of the years that EPA’s subtitle C regulations (which among other things, define what a solid wast e is for purposes of those regulations) have been in place. The RCRA subtitle C regulatory program consequently has not been anyan impediment to use of anthropogenic CO 2 for EOR.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 447 of 854 can be considered to be adequately demonstrated. Ma ny of the issues referred to in comments relate to property r ights: issues of ownership of pore space, relationship of sequest ration to ownership of mineral rights, issues of dealing with multiple landowners, lack of state law frameworks, or compet ing, inconsistent state laws. 513 Other commenters noted the lack of long-term liability insurance, and noted uncertaint ies regarding long-term liability generally. 514 An IPCC special report on CCS found that with an appropriate site selection, a monitoring program, a regulatory system, and the appropriate use of remediation meth ods, the risks of GS would be comparable to risks of current activities, such as EOR, acid gas injection and underground nat ural gas storage. 515 Furthermore, an interagency CCS task force examine d GS-related legal issues thoroughly and concluded th at early CCS projects can proceed under the existing legal frame work with respect to issues such as property rights and liabi lity. 516 As noted earlier, both the Archer Daniels Midland (ADM) and FutureGen projects addressed siting and operational aspects of

513 See e.g. Comments of Duke Energy, p. 28; UARG, p. 62; AEP, p. 91. 514 See e.g. Comments of UARG, pp. 26, 62; EEI, p. 92; Duke Energy, pp. 27, 28. 515 Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage. 516 http://www.epa.gov/climatechange/Downloads/ccs/CCS -TaskForce-Report-2010.pdf

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Page 448 of 854 GS (including issues relating to volumes of the CO 2 and the

nature of the CO 2 injectate) in their permit applications. The fact that these applicants pursued permits indicate s that they regarded any potential property rights issues as re solvable.

Commenter American Electric Power (AEP) referred to its own experience with the Mountaineer demonstrati on project. AEP noted that although this project was not full s cale, finding a suitable repository, notwithstanding a generally favorable geologic area, proved difficult. The company referr ed to years spent in site characterization and digging multiple wells. 517 Other commenters noted more generally that site cha racterization issues can be time-consuming and difficult, and quo ted studies suggesting that it could take 5 years to obtain a C lass VI permit. 518 The EPA agrees that robust site characterization an d selection is important to ensuring capacity needs a re met and that the sequestered CO 2 is safely stored. Efforts to characterize geologic formations suitable for GS ha ve been underway at DOE through the RCSPs since 2003 (see S ection KV.M ). Additionally, since 2007, the USGS has been assessi ng U.S. geologic storage resources for CO 2 . As noted earlier, DOE, in

517 AEP Comments at pp. 93, 96. 518 See e.g. Comments of UARG, p. 55, citing to Cichan owitz CCS Report (2012).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 449 of 854 partnership with researchers, universities, and org anizations across the country, is demonstrating that GS can be achieved safely, permanently, and economically at large scal es, and projects supported by the department have safely an d permanently stored 10 million metric tons of CO 2 . In the time since the commenter submitted comments several Class VI permits have been issued by the EPA. These projects demonstrate that a GS site permit applicant could p otentially prepare and obtain a UIC permit concurrent with per mits required for an EGU. With respect to AEP’s experience with t he Mountaineer demonstration project, notwithstanding difficulties, the company was able to successfully dig wells, and safely inject captured CO 2 . Moreover, the company indicated it fully expected to be able to do so at full scale and expl ained how. 519 The EPA notes further that a monitoring program and its associated infrastructure (e.g., monitoring wells) and costs will be dependent on site-specific characteristics, such as CO 2 injection rate and volume, geology, the presence of artificial penetrations, among other factors. It is thus not a ppropriate to generalize from AEP’s experience, and assume that o ther sites

519 See AEP FEED Study at pp. 36-43. The company likew ise explained the monitoring regime it would utilize to verify containment, and the well construction it would uti lize to guarantee secure sequestration. Id. at pp. 44-54. Available at: www.globalccsinstitute.com/publications/aep-mountai neer-iiproject-front-end-engineering-and-design-feed-repor t.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 450 of 854 will require the same number of wells for site char acterization or injection. In this regard, we note that the ADM and FutureGen construction permits for Class VI wells involved fa r fewer injection wells than AEP references. 520 See also discussion of this issue in Section V.I.5 above. NO. Non-air Quality Impacts and Energy Requirements As part of the determination that SCPC with partial CCS is the best system of emission reduction adequately de monstrated, the EPA has given careful consideration to non-air quality health and environmental impacts and energy require ments, as required by CAA section 111 (a). We have also consi dered those factors for alternative potential compliance paths to assure that the standard does not have unintended adverse health, environmental or energy-related consequences. The E PA finds that neither the BSER, nor the possible alternative comp liance pathways, would have adverse consequences from eith er a non-air quality impact or energy requirement perspective.

520 The FutureGen UIC Class VI injection well permits (four in total) require nine monitoring wells. http://www.epa.gov/r5water/uic/futuregen/. The Arch er Daniels Midland UIC Class VI injection well permit issued i n September 2014 (CCS2) requires five monitoring wells and the Archer Daniels Midland UIC Class VI injection well permit issued in December 2014 (CCS1) was permitted with two monitor ing wells. http://www.epa.gov/region5/water/uic/adm/.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 451 of 854 1. Transport and Sequestration of Captured CO 2 As just discussed in detail, the EPA finds that the Class VI and II rules, as complemented by the subpart RR GHGRP reporting and monitoring requirements, amply safegu ard against potential of injected CO 2 to degrade underground sources of drinking water and amply protect against any releas es of sequestered CO 2 to the atmosphere. The EPA likewise finds that the plenary regulatory controls on CO 2 pipelines assure that CO 2 can be safely conveyed without environmental releas e, and that these rules, plus the complementary tracking and re porting rules in subpart RR, assure that captured CO 2 will be properly tracked and conveyed to a sequestration site. 2. Water Use Impacts Commenters claimed that the EPA ignored the negativ e environmental impacts of the use of CCS for the mit igation of CO 2 emissions from fossil fuel-fired steam generating E GUs. In particular, commenters noted that the use of CCS wi ll increase the water usage at units that implement CCS to meet the proposed standard of performance. At least one commenter cla imed that addition of an amine-based CCS system would double the consumptive water use of a power plant, which would be unacceptable, especially in drought-ridden states a nd in the arid west and referenced a study in the scientific literature as*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 452 of 854 support. 521 The commenter also references a DOE/NETL report th at likewise notes significant increases in the amount of cooling and process water required with the use of carbon c apture technology. 522 However, those studies discuss increased water use for cases where full CCS (90 percent or greater cap ture) is implemented. As we discussed in both the proposal a nd in this preamble, the EPA does not find that highly efficie nt new generation technology implementing full CCS is the BSER for new steam generating EGUs. The EPA examined water use predicted from the updat ed DOE/NETL studies in order to determine the magnitud e of increased water usage for a new SCPC implementing p artial CCS to meet the final standard of 1,400 lb CO 2 /MWh-g. The predicted water consumption for varying levels of partial and full CCS are provided in Table 13. The results show that a new S CPC unit that implements 16 percent partial CCS to meet the final standard would see an increase in water consumption (the dif ference between the predicted water withdraw and discharge) of about 6.4 percent compared to an SCPC with no CCS and the sam e net power

521 See comments of UARG at p. 84 referencing Haibo Zh ai, et al. , Water Use at Pulverized Coal Power Plants with Post -combustion Carbon Capture and Storage, 45 Environ. Sci. Technol. , 2479-85 (2011). 522 Id at p. 84 referencing DOE/NETL-402/080108, “Wate r Requirements for Existing and Emerging Thermoelectr ic Plant Technologies” at 13 (Aug. 2008, Apr. 2009 revision)

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Page 453 of 854 output. By comparison, a unit implementing 35 perce nt CCS to meet the proposed emission limitation of 1,100 lb C O 2 /MWh-g would see an increase in water consumption of 16.0 percen t and a new unit implementing full (90 percent) CCS would see a n increase of almost 50 percent. Table 13. Predicted Water Consumption with Implemen tation of Various Levels of Partial CCS 523 Raw Water Increase Compared Technology Consumption, gpm to SCPC, % SCPC 4,095 - SCPC + 16% CCS 4,359 6.4 SCPC + 35% CCS 4,751 16.0 SCPC + 90% CCS 6,069 48.2

IGCC* 3,334 -18.6 IGCC + 90% CCS* 4,815 17.6 * The IGCC results presented in the DOE/NETL report are for an IGCC with net output of 622 MWe and an IGCC with fu ll CCS with net output of 543 MWe. The water consumption for ea ch was normalized to 550 MWe to be consistent with the SPC P cases.

Similar to other air pollution controls – such as a wet flue gas desulfurization scrubber – utilization of postcombustion amine-based capture systems results in i ncreased consumption of water. However, by finalizing a stan dard that is less stringent than the proposed limitation and by rejecting full CCS as the BSER, the EPA has reduced the incre ased amount

523 Exhibits A-1 and A-2 at p. 16-17 from “Cost and Pe rformance Baseline for Fossil Energy Plants Supplement: Sensi tivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL- 2015/1720 (June 22, 2015).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 454 of 854 of water needed as compared to a similar unit witho ut CCS. Further, the EPA notes that there are additional op portunities to minimize the water usage at such a facility. For example, the SaskPower Boundary Dam Unit #3 post-combustion capt ure project captures water from the coal and from the combustio n process and recycles the captured water in the process, resulti ng in decreased need for withdrawal of fresh water. The EPA also examined the predicted water usage for a new IGCC and for a new IGCC implementing 90 percent CCS . The predicted water consumption for the new IGCC unit i s nearly 20 percent less than that predicted for the new SCPC u nit without CCS (and almost 25 percent less than the SCPC unit meeting the final standard). The EPA rejected new IGCC implemen ting full CCS as BSER because the predicted costs were significan tly more than alternative technologies. The EPA also does not fin d that a new IGCC EGU is part of the final BSER (for reasons dis cussed in Section V.P). However, the EPA does note that IGCC is a viable alternative compliance option and, as shown here, w ould result in less water consumption than a compliant SCPC EGU . The EPA also notes that predicted water consumption at a ne w NGCC unit*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 455 of 854 would be less than half that for a new SCPC EGU wit h the same net output. 524 3. Energy Requirements The EPA also examined the expected impacts on energ y requirements for a new unit meeting the final promu lgated standard and finds impacts to be minimal. Specifica lly, the EPA examined the increased auxiliary load or parasitic energy requirements of a system implementing CCS. The EPA examined the predicted auxiliary power demand from the updated D OE/NETL studies in order to determine the increased energy requirement for a new SCPC implementing partial CCS to meet the final standard of 1,400 lb CO 2 /MWh-g. The predicted gross power output, the auxiliary power demand, and the parasitic power demand (percent of gross output) are provided in Table 14 for varying levels of partial and full CCS. Table 14. Predicted Parasitic Power Demand with Implementation of Various Levels of Partial CCS 525

524 The EPA also finds that the standards would not re sult in any significant impact on solid waste generation or man agement. See Section XIII.D below. 525 Exhibits A-1 and A-2 at p. 16-17 from “Cost and Pe rformance Baseline for Fossil Energy Plants Supplement: Sensi tivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL- 2015/1720 (June 2015).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 456 of 854

Generation Gross

Power Auxiliar

y Parasiti

c

Technology Output,

MWe Power,

MWe Demand

(%)

SCPC 580 30 5.2 SCPC + 16%

CCS 599 38 6.3 SCPC + 35%

CCS 603 53 8.8 SCPC + 90%

CCS 642 91 14.2

IGCC 748 126 16.8 IGCC + 90%

CCS 734 191 26.0

The auxiliary power demand is the amount of the gro ss power output that is utilized within the facility rather than used to produce electricity for sale to the grid. The paras itic power demand (or parasitic load) is the percentage of the gross power output that is needed to meet the auxiliary power d emand. 526 In

526 Note that this auxiliary power demand is not neces sarily met from power or steam generated from the EGU. Externa l sources can also be utilized for this purposes.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 457 of 854 an SCPC EGU without CCS, the auxiliary power is use d to primarily to operate fans, motors, pumps, etc. asso ciated with operation of the facility and the associated pollut ion control equipment. When carbon capture equipment is incorpo rated, additional power is needed to operate associated eq uipment, and steam is need to regenerate the capture solvents (i .e., the solvents are heated to release the captured CO 2 ). The results in Table 14 show that a new SCPC unit w ithout CCS can expect a parasitic power demand of about 5. 2 percent. A new SCPC unit meeting the final standard of perform ance by implementing 16 percent partial CCS will see a para sitic power demand of about 6.3 percent, which is not a signifi cant increase in energy requirement. Of course, new SCPC EGUs tha t implement higher levels of CCS will expect higher amounts of parasitic power demand. As shown in Table 14, a new SCPC EGU implementing full CCS would expect to utilize over 14 percent of its gross power output to operate the facility and the carbon capture system. But, the EPA does not find that a new SCPC implementing full CCS is the BSER for new fossil-fired steam gen erating units. See Section V.P.2 below. The EPA also notes that there is on-going research sponsored by DOE/NETL and others to further reduce the energy requirements of the carbon capture systems. Progres s is being made. As was mentioned previously, the heat duty (t he energy*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 458 of 854 required to regenerate the capture solvent) for the amine scrubbing process used at the Searles Valley facili ty in the mid-70’s was about 12 MJ/mt CO 2 removed as compared to a heat duty of about 2.5 MJ/mt CO 2 removed for the amine processes used at Boundary Dam and for the amine system that will be used at the WA Parish facility. 527 The EPA also examined the predicted parasitic power demand for a new IGCC and for a new IGCC implementing 90 p ercent CCS. As we have noted elsewhere, the auxiliary power dem and for a new IGCC unit is more than that for that of a new SCPC. As one can see in Table 14, a new IGCC unit can expect to see a nearly 17 percent parasitic power demand; and a new IGCC uni t implementing full CCS would expect a parasitic powe r demand of nearly 30 percent. Of course, the EPA rejected new IGCC implementing full CCS as BSER because of the potent ially unreasonable costs. The EPA also does not find that a new IGCC EGU is part of the final BSER (for reasons discusse d elsewhere in Section V.P.1 below). However, as we have noted, the EPA does find IGCC to be a viable alternative compliance opt ion. Utilities and project developers should consider th e increased auxiliary power demand for an IGCC when considering their

527 “From Lubbock, TX to Thompsons, TX - Amine Scrubbi ng for Commercial CO 2 Capture from Power Plants”, plenary address by Prof. Gary Rochelle at the 12 th International Conference on Greenhouse Gas Technology (GHGT-12), Austin, TX (Oc tober 2014).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 459 of 854 options for new power generation. The EPA also note s that the predicted parasitic load for a new NGCC unit would be about 2 percent - less than half that for a new SCPC EGU wi th the same net output. 528 With respect to potential nationwide impacts on ene rgy requirements, as described above in Section V.H.3 a nd more extensively in the RIA chapter 4, the EPA reasonabl y projects that no new non-compliant fossil-fuel fired steam e lectric capacity will be constructed through 2022 (the end of the 8 year review cycle for NSPS). It is possible, as describe d earlier, that some new sources could be built to preserve fu el diversity, but even so, the number of such sources would be sm all and therefore would not significantly impact national e nergy requirements (assuming that such sources would not already be reflected in the baseline conditions just noted).

P . Options That Were Considered by the EPA but Were Ultimately Not Determined to Be the BSER In light of the comments received, the EPA re-exami ned several alternative systems of emission reduction a nd reaffirms in this rulemaking our proposed determination that those alternatives do not represent the “best” system of emission

528 The EPA also finds that the standards would not re sult in any significant impact on solid waste generation or man agement. See Section XII.D below.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 460 of 854 reduction when compared against the other available emission reduction options. These are described below. See also Section IV.B.1 above. 1. Highly efficient generation technologyEfficient Generation Technology (e.g., Supercritical or Ultra- supercritical or ultrasupercritical boilersBoilers ) In the January 2014 proposal, we considered whether ‘Highly Efficient New Generation without CCS Technology’ sh ould constitute the BSER for new steam generating units. 79 FR at 1468-69. The discussion focused on the performance of highly efficient generation technology (that does not incl ude any implementation of CCS), such as a supercritical 529 pulverized coal (SCPC) or a supercritical CFB boiler, or a mod ern, wellperforming IGCC unit. All these options are technically feasible – there are numerous examples of each operating in the U.S. and worldwide. However, we do not find them to qualify as the best system for reduction of CO 2 emissions for the following reasons:

529 Subcritical coal-fired boilers are designed and op erated with a steam cycle below the critical point of water. Su percritical coal-fired boilers are designed and operated with a steam cycle above the critical point of water. Increasing the s team pressure and temperature increases the amount of energy with in the steam, so that more energy can be extracted by the steam t urbine, which in turn leads to increased efficiency and lower emi ssions.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 461 of 854 a. Lack of significant CO2 reductions when compared to business

as usual

. At the outset, we reviewed the emission rates of ef ficient PC and CFB units. According to the DOE/NETL estimat es 530 , a newly constructed subcritical PC unit firing bituminous c oal would emit approximately 1,800 lb CO 2 /MWh- gr,g, 531 a new highly efficient SCPC unit using bituminous coal would emit nearly 1, 700720 lb CO 2 /MWh- grg , and a new IGCC unit 532 would emit about 1, 450430 lb CO 2 /MWh- gr.g. 533, 534 Emissions from comparable sources utilizing sub-bituminous coal or lignite will have somewhat higher CO 2 emissions. 535

530 Exhibit ES-2 from “Cost and Performance Baseline f or Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 2010). 531 Exhibit ES-2 from “Cost and Performance Baseline f or Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 2010). 532 “Case 1” from Exhibit ES-2 from “Cost and Performa nce Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL-20 10/1397 (November 2010). 533 “Cost and Performance Baseline for Fossil Energy P lants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015); SCPC rates come from Exhibit A-2 and IGCC rates come from Exhibit A-4. 534 The comparable emissions on a net basis are: subcr itical PC – 1,890 lb CO 2 /MWh- net; supercritical PCn; SCPC – 1, 770705 lb CO 2 /MWh- netn ; and IGCC – 1, 720724 lb CO 2 /MWh- net.n. (See same references as for gross emissions provided in the t ext). 535 Exhibit ES-2 from “Cost and Performance Baseline f or Fossil Energy Plants Volume 3b: Low Rank Coal to Electrici ty: Combustion Cases”, Report DOE/NETL-2010/1463 (March 2011).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 462 of 854 Some commenters noted that new coal-fired plants ut ilizing supercritical boiler design or IGCC would provide s ubstantial emission reductions compared to the emissions from the existing subcritical coal plants that are currently in wide use in the power sector. However, the majoritymost of the most recent new power sector projects using solid fossil fuel (coal or petroleum coke) as the primary fuel – both those that have be en constructed and those that have been proposed – are supercritical boilers and IGCC units. Coal-fired power plants that have come on-line theAbout 60 percent of new c oal-fired utility boiler capacity that has come on-line since 2005 was supercritical and of the new capacity that came on- line since 2010, about 70 percent was supercritical. No new co al-fired utility boilers began operation in either 2013 or 2 014. Coalfired power plants that have come on-line most recently include AEP’s John W. Turk, Jr. Power Plant, which is a 600 MW ultrasupercritical 536 PC (USCPC) facility located in the southwest corner of Arkansas, and Duke Power’sEnergy’s Edwardsport plant, which is a 618 MW “CCS ready” 537 IGCC unit located in Knox

536 Ultra-supercritical (USC) and advanced ultra-super critical (A-USC) are terms often used to designate a coal-fi red power plant design with steam conditions well above the c ritical point. 537 A “CCS ready” facility is one that is designed suc h that the CCS equipment can be more easily added at a later t ime.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 463 of 854 County, Indiana. The majorityBoth of new coal-fired power plants that were broughtthose facilities came on-line in 2010 or later have utilized supercritical boiler technology. 538 And those2012. It is likely that the units that initiated operation in 2010 or later were conceived of, planned, designed, and per mitted well before 2010 – likely in the early 2000s. Thus, it s eems clear that the power sector had already, at that point, t ransitioned to the selection of supercritical boiler technology as “business as usual” for new coal-fired power plants. Since th at time, there have been other coal-fired power plants that have been proposed and almost all of them have been either su percritical boiler designs or IGCC units. In Table 1 of the Technical Support Document Fossil Fuel-Fired Boiler and IGCC EGU Projects Under Development: Status and Approach 539 for the January 2014 proposal, the EPA listed the development status of “potential transitional sources” (i.e., projects that had been proposed and had received Prevention of Significant Deterioratio n (PSD) preconstruction permits as of April 13, 2012). Of t he 16 proposed EGU projects in Table 1 – most of which ha ve been cancelled or converted to or replaced with NGCC pro jects – the

538 Exceptions would include a few smaller plants (e.g ., less than 300 MW) that are CHP units and a few subcritical PC and CFB sources. 539 Available in the rulemaking docket ID: EPA-HQ-OAR- 2013-0495- 0024.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 464 of 854 majority (nine) are either supercritical PC or IGCC designs. Five of the proposed projects were CFB designs with only one being a subcritical PC design. The EPA is aware of only one new coal-fired power p lant that is actively in the construction phase. That pl ant is Mississippi Power’s Kemper County Energy Facility i n Kemper County, MS – an IGCC unit that plans to begin operations in 2016

and will implement partial CCS to capture approximately 65 percent of the available CO 2 , which will be sold for use in EOR operations. Considering the direction that the power sector has been taking and the changes that it is undergoing, ident ifying a new supercritical unit as the BSER and requiring an emi ssion limitation based on the performance of such units t hus would provide few, if any, additional CO 2 emission reductions beyond the sector’s “business as usual”. As noted, for the most part, new sources are already designed to achieve at leas t that emission limitation. This criterion does not itself eliminate supercritical technology from consideration as BSER . However, existing technologies must be considered in the con text of the range of technically feasible technologies and, as we discuss elsewhere in this final preamble , partial CCS can achieve emission limitations beyond business as usual and d o so at a reasonable cost.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 465 of 854 The EPA also considered IGCC technology and whether it represents the BSER for new power plants utilizing coal or other solid fossil fuels. IGCC units, on a gross-output b asis, have inherently lower CO 2 emission rates when compared to similarlysized SCPC units. However, the net emission rates a nd overall emissions to the atmosphere (i.e., tons of CO 2 per year) tend to be more similar (though still somewhat lower) for n ew IGCC units when compared to new SCPC units with the same elect rical output. Therefore an emission limitation based on the expec ted performance of a new IGCC unit would result in some CO 2 emission reductions from the segment of the industry that wo uld otherwise construct new PC units, but not from the segment of the industry that would already construct new IGCC units. A gros s-outputbased emission limitation consistent with the expec ted performance of a new IGCC unit would still require some additional control, such as partial CCS, on a new s upercritical boiler. As is shown in Section [x.x],V.J and H, additional emission reductions beyond those that would result from an e mission standard based on a new SCPC boiler or even a new I GCC unit as the BSER can be achieved at a reasonable cost. Beca use practicable emission controls are available that ar e of reasonable cost at the source level and that will h ave little cost and energy impact at the national level, the E PA is*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 466 of 854 according significant weight to the factor of amoun t of emissions reductions in determining the BSER. As di scussed above, the D.C. Circuit has emphasized this factor in describing the purpose of CAA section 111 as to achieve “as mu ch [emission reduction] as practicable.” 540 b. Lack of incentive for technological innovation

. As discussed above, the EPA is justifying its identification of the BSER based on its weighing of the factors explicitly identified in CAA section 111(a)(1), inc luding the amount of the emission reduction. Under the D.C. Ci rcuit

caselawcase law , encouraging the development and implementation of advanced control technology must also be conside red . (and, in any case, may reasonably be considered; see Section V.H.3.d above). Consideration of this factor confirms the EPA’s de cision not to identify highly efficient generation technol ogy (without CCS) as the BSER. At present, CCS technologies are the most promising options to achieve significant reductions in CO 2 emissions from newly constructed fossil - fuel - fired steam generating units. CCS technology is also now a viab le retrofit option for some modified, reconstructed and existin g sources – depending upon the configuration, location and age of those sources. As CCS technologies are deployed and used more there is

540 Sierra Club , 657 F.2d at 327 & n. 83.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 467 of 854 an expectation that, based on previous experience w ith advanced technologies, the performance will improve and the implementation costs will decline. The improved per formance and lower costs will provide additional incentive for f urther implementation in the future.

The InternationalIntergovernmental Panel on Climate Change (IPCC) recently released its Fifth Assessment repor t 541 , which recognizes that widespread deployment of CCS is cru cial to reach the long term climate goals. The authors of the rep ort used models to predict the likelihood of stabilizing the atmospheric concentration of CO 2 at 450 ppm by 2050 with or without carbon capture and storage (CCS). They found that several of the models were not able to reach this goal without CCS, which underlines the importance of deploying and further developing CCS on a large scale. American Electric Power (AEP), in an evaluation of lessons learned from the Phase 1 of its Mountaineer CCS pro ject, wrote: “AEP still believes the advancement of CCS is criti cal for the sustainability of coal-fired generation.” 542

541 IPCC, Working Group III, Climate Change 2014: Miti gation of Climate Change, http://mitigation2014.org/report/pu blication //. 542 CCS LESSONS LEARNED REPORT American Electric Power Mountaineer CCS II Project Phase 1, Prepared for Th e Global CCS Institute Project # PRO 004, January 23, 2012, page 2. See also AEP FEED Study at pp. 4, 63 (same). Available at: http://www.globalccsinstitute.com/publications/aep- mountaineerii-project-front-end-engineering-and-design-feed-re port.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 468 of 854 Some commenters felt that the proposed standard of performance for new steam generating units, based o n implementation of partial CCS at an emission rate o f 1,100 lb/MWh- grossg , would not serve to promote the increased deployment and implementation of CCS. The commenter s argued that such a standard could instead have the unintended r esult of discouraging the further development of advanced co al generating technologies such as ultra-supercritical boilers an d improved IGCC designs. Commenters further argued that such a standard will stifle further development of CCS technologies. Commenters felt that the standard would effectively deter the constructi on of new coal-fired generation – and, if there is no new coa l-fired generation, then there will be no implementation of CCS technology and, therefore, no need for continued re search and development of CCS technologies. They argued, in fa ct, that the best way to promote the development of CCS was to s et a standard that did not rely on it. The EPA does not agree with these arguments and, in particular, does not see how a standard that doesis not requirepredicated on performance of an advanced control technology would serve to promote development and d eployment of that advanced control technology. On the contrary, the history of regulatory actions has shown that emission stand ards that*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 469 of 854 require the installationare based on performance of advanced control equipment lead to increased use of that con trol equipment, and that the absence of a requirement stifles technology development. There is a dramatic instance of this paradigm prese nted in the present record. In 2011, AEP deferred construct ion of a large-scale CCS retrofit demonstration project on o ne of its coal-fired power plants because the state’s utility regulators would not approve cost recovery for CCS investments without a regulatory requirement to reduce CO 2 emissions. AEP’s chairman was explicit on this point, stating in a July 17, 2 011 press release announcing the deferral: We are placing the project on hold until economic a nd policy conditions create a viable path forward ... We are clearly in a classic ‘which comes first?’ situation. The commercialization of this technology is vital if ow ners of coalfueled generation are to comply with potential futu re climate regulations without prematurely retiring efficient, costeffective generating capacity. But as a regulated u tility, it is impossible to gain regulatory approval to recover o ur share of the costs for validating and deploying the technolo gy without federal requirements to reduce greenhouse gas emiss ions already*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 470 of 854 in place. The uncertainty also makes it difficult t o attract partners to help fund the industry’s share. 543

Some commenters also argued that the incremental co st associated with including CCS at the proposed level would prevent new coal-fired units from being built. Inst ead, they advocated for a standard based on most efficient te chnology (supercritical) coupled with government subsidies t o advance and promote CCS technology. As we will show later, theThe final

standard that we are issuing in this action is less stringent

than thethat proposed level, and can be met at a lower cost than the proposed standard , and as explained above in Section V.H, the EPA has carefully evaluated those costs and fin ds them to be

reasonable . Further, the record and current economic conditio ns (fuel costs, renewables, demand growth, etc.) show that noneconomic factors such as a desire for fuel diversit y will likely drive future development of any new coal-fired EGUs. InFor this reason, the EPA does not find the commenters’ bare assertions

that scenariothe incremental cost of CCS (particularly a s reasonably modulated for this final standard) would make the difference between constructing and not constructin g new coal capacity to be persuasive. Rather , a cost-reasonable standard

543 http://www.aep.com/newsroom/newsreleases/?id=1704

.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 471 of 854 reflecting use of the new technology is , in fact, what will drive new technology deployment. The EPA expects that it is unlikely that a new IGCC unit would install partial CCS to meet the final standar d unless the facility is built to take advantage of EOR opportun ities or to operate as a poly-generation facility (i.e., to co- produce power along with chemicals or other products). For mostnew IGCC units, the final standard of performance can be met simply by co-firing a small amount of natural gas. Some commenters argu ed that IGCC is an advanced technology that, like CCS, should be promoted. The EPA agrees. IGCC is a low-emitting, versatile t echnology that can be used for purposes beyond just power pro duction (as mentioned just above). Commenters further argued th at a requirement to include partial CCS (at a level to m eet the proposed standard of performance) would serve to de ter – rather than promote – more installation of IGCC technology . We disagree with a similar argument that commenters make with r espect to partial CCS for post-combustion facilities, but our final standard moots that argument for IGCC facilities be cause the final emission limitation of 1,400 lb CO 2 /MWh- grossg will not*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 472 of 854 itself deter installation of IGCC technology, by th e terms of the commenters’ own argument. 544 2. “Full” carbon captureCarbon Capture and storageStorage (i.e., 90 percent capturePercent Capture ) We also reconsidered whether the emission limitatio n for new coal-fired EGUs should be based on the performa nce of full implementation of CCS technology. For a newly const ructed utility boiler, this would mean that a post-combust ion capture system would be used to treat the entire flue gas s tream to achieve an approximately 90 percent reduction in CO 2 emissions. For a newly constructed IGCC unit, a pre-combustion capture system would be used to capture CO 2 from a fully shifted gasification syngas stream to achieve an approximat ely 90 percent reduction in CO 2 emissions. In the proposal for newly constructed sources (January 2014 proposal),, we found that “full CCS” would certainly result in significant CO 2 reductions from any new source implementing the technology. However, we also found that the costs a ssociated with implementation, on either a new utility boiler system or a new IGCC unit, are predicted to substantially excee d the costs

544 Commenters stated: While the final standard of per formance should not deter the installation of new IGCC gener ation, the technology still faces hurdles due to its higher co st relative to the cost of a new SCPC plant and, more important ly, relative to the cost of new NGCC facility.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 473 of 854 for other dispatchable non-NGCC generating options that are being considered by utilities and project developer s (e.g., new nuclear plants and new biomass-fired units). See 79 FR at 1477. This remains the case, and indeed, the difference b etween cost of full capture and new nuclear technology is estimated to be even greater than at proposal. The EPA thus is not selecting full capture CCS as BSER. Q. Summary The EPA finds that the best system of emission redu ction adequately demonstrated is a highly efficient super critical pulverized coal boiler using post-combustion partia l CCS so that

CO 2 is captured, compressed and safely stored over the longterm. Properly designed, operated, and maintained, this best system can achieve a standard of performance of 1,4 00 lb CO 2 /MWhg, an emission limitation that is achievable over t he 12- operating-month compliance period considering usual operating variability (including use of different coal types, periods of startup and shutdown, and malfunction conditions). This standard of performance is technically feasible, gi ven that the BSER technology is already operating reliably in fu ll-scale commercial application. The technology adds cost to a new facility which the EPA has evaluated and finds to b e reasonable because the costs are in the same range as those fo r new nuclear generating capacity – a competing non-NGCC, dispatc hable*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 474 of 854 technology that utilities and project developers ar e also considering for base load application. The EPA has also considered capital cost increases associated with u se of postcombustion partial CCS at the level needed to meet the final standard and found them to be reasonable, and withi n the range of capital cost increases for this industry in prio r NSPS which have been adjudicated as reasonable. The EPA’s cons ideration of costs is also informed by its judgment that new coa l-fired capacity would be constructed not as the most econo mic option, but for such purposes as preserving fuel diversity in an energy portfolio, and so would not be cost competitive wit h natural gas-fired capacity, so that some additional cost pr emium may therefore be reasonable. The EPA has carefully eval uated the non-air quality health and environmental impacts of the final

standard and found them to be reasonable: CO 2 pipelines and CO 2 sequestration via deep well injection are subject a lready to rigorous control under established regulatory progr ams which assure prevention of environmental release during t ransport and storage. In addition, water use associated with use of partial CCS at the level to meet the final standard is acce ptable, and use of the technology does not impose significant b urdens on energy requirements at either the plant or national level. The 1,400 lb CO 2 /MWh-g standard reflecting performance of the BSER may be achieved without geographic constraint, both because*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 475 of 854 geologic sequestration and EOR capacity are widely available and accessible, and also because alternative compliance pathways are available in the unusual circumstance where a new c oal-fired plant is sited in an area without such access, that area has not already limited construction of new coal-fired capa city in some way, and the area cannot be serviced by coal-by-wir e. Accordingly, the EPA finds that the promulgated sta ndard of performance for new fossil fuel-fired steam electri c generating units satisfies the requirements of CAA section 111 (a). VI. Rationale for Final Standards for Modified Foss il Fuel-fired Electric Utility Steam Generating Units The EPA has determined that, as proposed, the BSER for steam generating units that trigger the modificatio n provisions is each affected unit’s own best potential performa nce as determined by that unit’s historical performance. T he final standards of performance are similar to those propo sed in the June 2014 proposal. Differences between the propose d standards and the final standards issued in this action refle ct responses to comments received on the proposal. Those changes are described below. As noted previously, the EPA is issuing final emiss ion standards only for affected modified steam generati ng units that conduct modifications resulting in a potential hourly increase in CO 2 emissions (mass per hour) of more than 10 percent ("large"*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 476 of 854 modifications). The EPA is continuing to review the appropriate standards for modified sources that conduct modific ations resulting in a potential hourly increase in CO 2 emissions (mass per hour) of less than or equal to 10 percent ("sma ll" modifications), is not issuing final standards for thesethose sources in this action, and is withdrawing the prop osed

standards for thesethose sources. See Section XV below.

A. Rationale for Final Applicability Criteria for Modi fied Steam Generating Units Final applicability criteria for modified steam gen erating EGUs include those discussed earlier in section [x.x]Section III.A.1 (General Applicability) and section [x.x]Section III.A.3 (Applicability Specific to Modified Sources). CAA section 111(a)(4) defines a “modification” as “ any physical change in, or change in the method of oper ation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results i n the emission of any air pollutant not previously emitte d.” Certain types of physical or operational changes are exempt from consideration as a modification. Those are describe d in 40 CFR 60.2, 60.14(e). To be clear, our action in this fin al rule, and the discussion below, does not change anything conc erning what*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 477 of 854 constitutes or does not constitute a modification u nder the CAA or the EPA’s regulations. 545 A modified steam generating unit is a source that f its the definition and applicability criteria of a fossil f uel-fired steam generating unit and that commences a qualifyi ng modification on or after June 18, 2014 (the publica tion date of the proposed modification standards). 79 FR 34960. For the reasons discussed below, the EPA in this fi nal action is finalizing requirements only for steam ge nerating units that conduct modifications resulting in an in crease in potential hourly CO 2 emissions (mass per hour) of more than 10 percent as compared to the source’s potential to emithighest hourly emission during the previous five years. With respect to modifications with smaller increases in CO 2 emissions (specifically, steam generating units that conduct modifications resulting in an increase in potential hourly CO 2 emissions (mass per hour) of 10 percent or less compared to the sou rce’s potential to emithighest hourly emission during the previous 5

years ,), the EPA is not finalizing any standard or other requirements, and in a separate action today is withdrawing the June 2014 proposal with respect to these sources . (see Section

545 CAA section 111(a)(4); See also 40 CFR 60.14 conce rning what constitutes a modification, how to determine the em ission rate, how to determine an emission increase, and specific actions that are not, by themselves, considered modifications.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 478 of 854 XV below). The effect of the EPA’s deferral on setting standar ds for sources undertaking modifications resulting in smal ler increases in CO 2 emissions and the withdrawal of the June 2014 prop osal with respect to such sources is that such sources w ill continue to be existing sources and subject to requirements under section 111(d). This is because an existing source does not always become a new source when it modifies. Under the def inition of “new source” in section 111(a)(2), an existing sour ce only becomes a new source if it modifies after the publi cation of proposed or final regulations that will be applicab le to it. Thus, if an existing source modifies at a time that there is no promulgated final standard or pending proposed stan dard that will be applicable to it as a modified “new” source , that source is not a new source and continues to be an existing source. Here, because the EPA is not finalizing standards f or sources undertaking modifications resulting in smaller incr eases in CO 2 emissions and is withdrawing the proposal with resp ect to such sources, these sources do not fall within the defin ition of “new source” in section 111(a)(2) and continue to be an “existing source” as defined in section 111(a)(6). See Sectio n XV below. As we discussed in the June 2014 proposal, the EPA has historically been notified of only a limited number of NSPS*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 479 of 854 modifications 546 involving fossil steam generating units and therefore predicted that very few of these units wo uld trigger the modification provisions and be subject to the p roposed

standards. Given the limited information that we have about pa st modifications, the agency has concluded that it lac ks sufficient information to establish standards of performance f or all types of modifications at steam generating units at this time. Instead, the EPA has determined that it is appropri ate to establish standards of performance at this time for larger modifications, such as major facility upgrades invo lving, for example, the reconstructionrefurbishing or replacement of steam turbines and other equipment upgrades that result i n substantial increases in a unit’s potential hourly CO 2 emissions rate. The Agencyagency has determined, based on its review of public comments and other publicly available information, that it has adequate information regarding the types of modific ations that could result in large increases in potential hourly CO 2 emissions, as well as on the types of measures avai lable to control emissions from sources that undergo such mo difications, and on the costs and effectiveness of such control measures, upon which to establish standards of performance fo r

546 NSPS modifications resulting in increases in hourl y emissions of criteria pollutants.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 480 of 854 modifications with large emissions increases at thi s time. In establishing standards of performance at this ti me for modifications with large emissions increases, but n ot for those with small increases, the EPA is exercising its pol icy discretion to promulgate regulatory requirements in a sequential fashion for classes of modifications within a sourc e category, accounting for the information available to the age ncy, while also focusing initially on those modifications with the greatest potential environmental impact. This approach is consistent with the case law that authorizes agencies to establish a regulatory framework in an incremental fashion, that is, a ste p at a time. 547

547 As the U.S. Supreme Court recently stated in Massachusetts v. EPA, 549 U.S. 497, 524 (2007): “‘Agencies, like legislat ures, do not generally resolve massive problems in one fell regulatory swoop;’” and instead they may permissibly implement such regulatory programs over time, “‘refining their pre ferred approach as circumstances change and as they develo p a more nuanced understanding of how best to proceed.’” See Grand Canyon Air Tour Coalition v. F.A.A., 154 F.3d 455 (D.C. Cir. 1998), City of Las Vegas v. Lujan, 891 F.2d 927, 935 (D.C. Cir. 1989), National Association of Broadcasters v. FCC, 740 F.2d 1190, 1209–14 (DC Cir. 1984). See also, Hazardous Waste T reatment Council v. U.S. E.P.A., 861 F.2d 277, 287 (D.C. Cir . 1988) ("[A]n agency's failure to regulate more comprehens ively is not ordinarily a basis for concluding that the regulati ons already promulgated are invalid. 'The agency might properl y take one step at a time.' United States Brewers Assoc. v. E PA, 600 F.2d 974,982 (D.C. Cir. 1979). Unless the agency's firs t step takes it down a path that forecloses more comprehensive r egulation, the first step is not assailable merely because the agency failed to take a second. The steps may be too plod ding, but that raises an entirely different issue . . . .").*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 481 of 854 To be clear, the EPA is not reaching a final decisi on thatas to whether it will regulate modifications with smaller increases, or even that such modifications should b e subject to different requirements than we are finalizing in th is rule for the modifications with larger increases. We have ma de no decisions and this matter is not concluded. We plan to continue to gather information, consider the options for mod ifications with smaller increases, and, in the future, develop a proposal for these modifications or otherwise take appropria te steps. In deferring issuance of standards of performance f or those sources that conduct modifications resulting in a p otential hourly increase in CO 2 emissions of less than or equal to 10 percent, the EPA is exercising its discretion to pr opose and promulgate standards covering sources within a sour ce category in a sequential manner, under appropriate circumsta nces, such as those present here, consistent with the case law th at authorizes agencies to establish a regulatory framework in an incremental*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 482 of 854 fashion, that is, a step at a time. 548,549 As a means of determining the proper threshold betw een the larger and smaller increases in CO 2 emissions, the EPA examined changes in CO 2 emissions that may result from large, capitalintensive projects, such as major facility upgrades involving

the reconstructionrefurbishing or replacement of steam turbines and other equipment upgrades that would significant ly increase a unit's capacity to burn more fossil fuel, thereby r esulting in large emissions increases. Major upgrades such as t hese could increase a steam generating unit's potential hourly CO 2 emissions

548 As the U.S. Supreme Court recently stated in Massachusetts v. EPA, 549 U.S. 497, 524 (2007): ‘‘Agencies, like legislat ures, do not generally resolve massive problems in one fell regulatory swoop;’’ and instead they may permissibly implement such regulatory programs over time, ‘‘refining their pre ferred approach as circumstances change and as they develo p a more nuanced understanding of how best to proceed.’’ See Grand Canyon Air Tour Coalition v. F.A.A., 154 F.3d 455 (DC Cir. 1998), City of Las Vegas v. Lujan, 891 F.2d 927, 935 (DC Cir. 1989), National Association of Broadcasters v. FCC, 740 F.2d 1190, 1209–14 (DC Cir. 1984). 549 As the D.C. Circuit stated in Hazardous Waste Treatment Council v. U.S. E.P.A ., 861 F.2d 277, 287 (D.C. Cir. 1988)."[A]n agency's failure to regulate more comprehensively i s not ordinarily a basis for concluding that the regulati ons already promulgated are invalid. 'The Agency might properl y take one step at a time.' United States Brewers Assoc. v. E PA, 600 F.2d 974,982 (D.C. Cir. 1979). Unless the agency's firs t step takes it down a path that forecloses more comprehensive r egulation, the first step is not assailable merely because the agency failed to take a second. The steps may be too plod ding, but that raises an entirely different issue . . . ."*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 483 of 854 by well over 10 percent. 550 Therefore we are setting the threshold between “lar ge” modifications and “small” modifications subcategory An example of such major upgrade would be work performed at Amere nUE’s Labadie Plant, a facility with four 600-MW (nominal) coal-f ired units located 35 miles west of St. Louis. In the early 20 00s, plant staff conducted process improvements that raised ma ximum unit capacity by nearly 10 percent (from 580 MW to 630 M W). 551 Those changes included boiler improvements necessitated b y its switch from bituminous to subbituminous coal 552 , installation of low-NO X burners, an overfire air system, and advanced compu ter controls. One of the performance gains came from upgrading al l four steam turbines, which AmerenUE chose to replace as module s allowing engineers more freedom to maximize performance unco nstrained by the units’ existing outer casing. Another example is the refurbishment of the 2,100 M W Eskom Arnot coal-fired power plant in South Africa with a resulting

550 See e.g., Power Engineering, Steam Turbine Upgrade s Boost Plant Reliability, Efficiency, available at http:// www.powereng.com/articles/print/volume-116/issue-11/features /steamturbine-upgrades-boost-plant-reliability-efficiency .html. 551 “Steam turbine upgrading: Low-hanging fruit”, Powe r (04/15/2006), www.powermag.com/steam-turbine-upgrad ing-lowhanging-fruit. 552 Note that a change in coal-type or change in the u se of other raw material does not necessarily constitute an “op erational change”. See 40 CFR 60.14(e)(4).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 484 of 854 increase in its power output by 300 MW to 2,400 MW – an increase in capacity of 14 percent. 553 For each of the plant’s six steam generating units, the company conducted a complete retrofit of the high pressure and intermediate pressure steam t urbines, a capacity upgrade of the low pressure steam turbine, and the replacement and upgrade of associated turbine side pumps and auxiliaries. In addition, major upgrades to the boi ler plant were conducted, including supply of new pressure pa rt components, new burners, and modification to other equipment such as the coal mills and classifiers, fans, and h eaters. Other examples are provided in a technical memo available in the rulemaking docket. 554 The EPA does not intend to imply that these specifi c projects would have resulted in an increase in hour ly CO 2 emissions of greater than 10 percent. Capacity incr eases are often the result of efficient improvements or are a ccompanied by other facility improvements that can offset emissio ns increases due to increased fuel input capacity. However, thes e examples are intended to show the types of large, more capit al intensive

553 www.alstom.com/press-centre/2006/10/alstom-signs-p ower-plantupgrade-and-retrofit-contract-with-eskom-in-south-a frica/. 554 See “U.S. DOE Information Relevant to Technical Ba sis for “Large Modification” Threshold” available in the ru lemaking docket EPA-HQ-OAR-2013-0495.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 485 of 854 projects that can potentially result in increases i n hourly emissions of CO 2 of at least 10 percent. The EPA believes that it is reasonable to set the t hreshold between “large” modifications and “small” modificat ions at 10 percent, a level commensurate with the magnitude of the emissions increases that could result from thesethe types of projects described above , and we are issuing a final standard of performance for those sources that conduct modifica tions resulting in potential hourly CO 2 emission increases that exceed that threshold. We are not issuing standards of per formance for those sources that conduct modifications resulting in a potentialan hourly increase of CO 2 emissions of less than or equal to 10 percent. Therefore, in a separate action (published in a separate notice in the Federal Register today), the EPA is withdrawing the proposed standards for those sources that condu ct modifications resulting in a potential hourly increase in CO 2 emissions (mass per hour) of less than or equal to ten percent and is not issuing final standards for those source s at this time. See Section XV below. Utilities, states and others should

be aware that the differentiation between modifications with larger and smaller increases in CO 2 emissions only applies to sources covered under 40 CFR part 60, subpart TTTT, i.e., it is only applicable to CO 2 emissions from fossil fuel-fired steam*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 486 of 854 generating units. There is no similar provision for criteria pollutants or for other source categories. Utilitie s, states and others should also be aware that the distinction be tween large and small modifications only applies to NSPS modifi cations. Sources undertaking modifications may still be subj ect to requirements of New Source Review under CAA part CTitle I part C or D (which have different standards for modificati ons than the NSPS and require a case-by-case analysis) or other CAA requirements. The EPA notes that some commenters expressed concer n that a number of existing fossil steam generating units, i n order to fulfill requirements of an approved CAA section 111 (d) plan, may pursue actions that involve physical or operational changes that result in some increase in their CO 2 emissions on an hourly basis, and thus constitute modifications. Some comm enters suggested that the EPA should exempt projects under taken specifically for the purpose of complying with CAA section 111(d). The EPA does not have sufficient information at thi s time to predict the full array of actions that existing steam generating units may undertake in response to appli cable requirements under an approved CAA section 111(d) p lan, or which, if any, of these actions may result in incre ases in potential CO 2 hourly emissions. Nevertheless, the EPA expects*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 487 of 854 that, to the extent actions undertaken by existing steam generating units in response to 111(d) requirements trigger modifications, the magnitude of the increases in potential hourly CO 2 emissions associated with such modifications would generally be smallsmaller and would therefore generally not subject such modifications to the standards of perf ormance that the EPA is finalizing todayin this rule for modified steam generating units with largelarger increases in potential hourly

CO 2 emissions. We note that modified steam generating units that are not subject to the standard of performance finalized in this rule would be existing sources subject to section 111(d)

. 555 B. Identification of the Best System of Emission Re duction The EPA has determined that, as was proposed, the B SER for steam generating units that trigger the modificatio n provisions is the affected source’sEGU’s own best potential performance as

555 Any source that undergoes a modification resulting in CO2 increases of less than 10 percent will continue to be an “existing source” and so will be covered by require ments under section 111(d). Under the definition of “existing source” in section 111(a)(6), an existing source is any source that is not a new source. Under the definition of “new source” in section 111(a)(2), a modified source is a new source only i f the modification occurs after the publication of regula tions (or proposed regulations, if earlier) that will be appl icable to that source. Because we are not finalizing regulat ions with respect to the modifications with small CO2 increas es, and are withdrawing the proposal with respect to such sourc es, there are neither final regulations nor pending proposed regu lations which will be applicable to such modifications.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 488 of 854 determined by that source’s historical performance. The EPA proposed that the BSER for modified steam generating EGUs is each unit’s own best potential p erformance based on a combination of best operating practices and equipment upgrades. Specifically, the EPA co-proposed two alt ernative standards for modified utility steam generating uni ts. In the first co-proposed alternative, modified steam gener ating EGUs would be subject to a single emission standard dete rmined by the

affected source’sEGU’s best demonstrated historical performance (in the years from 2002 to the time of the modifica tion) with an additional 2 percent emission reduction. The EPA pr oposed that the standard could be met through a combination of best operating practices and equipment upgrades. To acco unt for facilities that have already implemented best pract ices and equipment upgrades, the proposal also specified tha t modified facilities would not have to meet an emission stand ard more stringent than the corresponding standard for recon structed

EGUs. The EPA also co-proposed that the specific standard for modified sources would be dependent on the timing o f the modification. We proposed that sources that modify prior to becoming subject to a CAA section 111(d) plan would be required to meet the same standard described in the first co -proposal— that is, the modified source would be required to m eet a unit-*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 489 of 854 specific emission limit determined by the affected source’sEGU’s best demonstrated historical performance (in the ye ars from 2002 to the time of the modification) with an additional 2 percent emission reduction (based on equipment upgrades). W e also proposed that sources that modify after becoming su bject to a CAA section 111(d) plan would be required to meet a unitspecific emission limit that would be determined by the CAA section 111(d) implementing authority and would be based on the source’s expected performance after implementation of identified unit-specific energy efficiency improvement opportu nities. The final standards in this action do not depend up on when the modification commences (as long as it commences after June 8, 2014). The EPA received comments on the June 201 4 proposal that called into question the need to differentiate the standard based on when the modification was undertaken. Furt her, commenters noted that the proposed requirements for sources modifying after becoming subject to a CAA section 1 11(d) plan, which were based on energy efficiency improvement o pportunities were vague and that standard setting under CAA sect ion 111(b) is a federal duty and would require notice-and-comment rulemaking. The EPA considered those comments and has determine d that we agree that there is no need for subcategories based on the timing of the modification.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 490 of 854

C. BSER Criteria 1. Technical Feasibility The EPA based technical feasibility of the unit-spe cific efficiency improvement on analyses done to support heat rate improvement for the proposed CAA section 111(d) emi ssion guidelines (Clean Power Plan). That work was summar ized in Chapter 2 of the TSD, “GHG Abatement Measures”. 556 In response to comments on the proposed Clean Power Plan, the appr oach was adjusted, as described in the final CAA section 111 (d) emission guidelines. As with proposed actions, the EPA is ba sing technical feasibility for final standards for modif ied source efficiency improvements on the analyses for heat ra te improvements for the CAA 111(d) final rule. 2. Cost Any efficiency improvement made by EGUs for the pur pose of reducing CO 2 emissions will also reduce the amount of fuel that EGUs consume to produce the same electricity output . The cost attributable to CO 2 emission reductions, therefore, is the net cost of achieving heat rate improvements after any savings from reduced fuel expenses. As summarized below, we esti mate that, on average, the savings in fuel cost associated with a 4 percent heat rate improvement would be sufficient to cover much of the

556 Technical Support Document “GHG Abatement Measures ” available in the rulemaking docket EPA-HQ-OAR-2013-0495.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 491 of 854 associated costs, and thus that the net costs of he at rate improvements associated with reducing CO 2 emissions from affected EGUs are relatively low. We recognize that our cost analysis just described will represent the costs for some EGUs better than other s because of differences in EGUs’ individual circumstances. We f urther recognize that reduced generation from coal-fired E GUs will tend to reduce the fuel savings associated with heat rat e improvements, thereby raising the effective cost of achieving

the CO 2 emission reductions from the heat rate improvement s. Nevertheless, we still expect that the majority of the investment required to capture the technical potent ial for CO 2 emission reductions from heat rate improvements wou ld be offset by fuel savings, and that the net costs of implemen ting heat rate improvements as an approach to reducing CO 2 emissions from modified fossil fuel-fired EGUs are reasonable. The EPA further notes that the types of large, more capital intensi ve projects that may trigger the “larger modifications” thresho ld (i.e., result in an hourly increase in CO 2 emissions) often are undertaken in order to increase the capacity of the source but also to improve the heat rate or efficiency of the unit. 3. Emission Reductions This approach would achieve reasonable reductions i n CO 2 emissions from the affected modified units as those units will*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 492 of 854 be required to meet an emission standard that is co nsistent with more efficient operation. In light of the limited o pportunities for emission reductions from retrofits, these reduc tions are adequate. 4. Promotion of Technology Promotionand Other Systems of Emission Reduction As noted previously, the case law makes clear that the EPA is to consider the effect of its selection of the B SER on technological innovation or development, but that t he EPA also has the authority to weigh this factor, along with the various other factors. With the selection of emissions cont rols, modified sources face inherent constraints that new ly constructed greenfield and even reconstructed sourc es do not; as a result, modified sources present different, and i n some ways more limited, opportunities for technological innov ation or development. In this case, the standards promote te chnological development by promoting further development and ma rket penetration of equipment upgrades and process chang es that improve plant efficiency.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 493 of 854 VII. Rationale for Final Standards for Reconstructe d Fossil Fuel-fired Electric Utility Steam Generating Units A. Rationale for Final Applicability Criteria for R econstructed

Sources The applicability rationale for reconstructed utili ty steam generating units is the same as for newly construct ed utility steam generating units. We are finalizing the same general criteria and not amending the reconstruction provis ions included in the general provisions. B. Identification of the Best System of Emission Re duction In the proposal, the EPA evaluated seven different control technology configurations to determine the BSER for reconstructed fossil fuel-fired boiler and IGCC EGU s: (1) The use of partial CCS, (2) conversion to (or co-firing with) natural gas, (3) the use of CHP, (4) hybrid power p lants, (5) reductions in generation associated with dispatch c hanges, renewable generation, and demand side energy effici ency,(6) efficiency improvements achieved through the use of the most efficient generation technology, and (7) efficiency improvements achieved through a combination of best operating pr actices and equipment upgrades. Although the EPA concluded that the first 4 technol ogies met most of the evaluation criteria, namely they ar e adequately demonstrated, have reasonable costs and provide GHG emissions*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 494 of 854 reductions, they were inappropriate for BSER due to site specific constraints for existing EGUs on a nationw ide basis. We rejected best operating practices and equipment upg rades because we concluded the GHG reductions are not sufficient to qualify as BSER. The majority of commenters agree with the EPA's decision that these technologies are not BSER. In contrast, as described in more detail later in this section a few commenters did support partial CCS as BSER. The fifth option, reductions in generation associat ed with dispatch changes, renewable generation, and demand side energy efficiency, is comparable to application of measure s identified in building blocks two, three and four in the emiss ions guidelines that we are finalizingproposed under CAA section 111(d). We solicited comment on any additional cons iderations that the EPA should take into account in the applic ability of building blocks two, three and four in the BSER det ermination. Most commenters stated that building blocks two, th ree and four should not be considered for reconstructed sources. The proposed BSER was based on the performance of t he most efficient generation technology available, which we concluded was the use of the best available subcritical steam conditions for small units and the use of supercritical steam conditions for large units. We concluded this technology to be technically feasible, to have sufficient emission reductions, t o have*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 495 of 854 reasonable costs, and some opportunity for technolo gical innovation. The proposed emission standard for thes e sources was 1,900 lb CO 2 /MWh- netn for units with a heat input rating of greater than 2,000 MMBtu/h and 2,100 lb CO 2 /MWh- netn for units with a heat input rating of 2,000 MMBtu/h or less. The difference in the proposed standards for larger and smaller units was based on greater availability of higher pressure/temperature steam turbines (e.g. supercrit ical steam turbines) for larger units. As explained in Section III of this preamble, we are finalizing the standard on a gross output basis for utility steam generating units. The equivalent gross-outputbased standards are 1,800 lb CO 2 /MWh and 2,000 lb CO 2 /MWh respectively. We solicited comment on multiple aspects of the pro posed standards. First, we solicited comment on a range o f 1,600 to 2,000 lb CO 2 /MWh- grossg for large units and 1,800 to 2,200 lb

CO 2 /MWh- grossg for small units. We also solicited comment on whether the standards for utility boilers and IGCC units should be subcategorized by primary fuel type. In addition , we solicited comment on if there are sufficient altern ate compliance technologies (e.g., co-firing natural ga s) that the small unit subcategory is unnecessary and should be eliminated. Those small sources would be required to meet the s ame emission standard as large utility boilers and IGCC units.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 496 of 854 Many commenters supported the upper limits of the s uggested ranges, saying the standard will be consistently me t. Some commenters raised concerns about the achievability of these limits for the many boiler and fuel types. A few co mmenters suggested that there should be separate subcategori es for coalfired utility boilers and IGCC units, since IGCC un its have demonstrated limits closer to 1,500 lb CO 2 /MWh- netn and the units' designs are so fundamentally different. Some commenters said that CFB (due to lower maximum steam temperatu res), IGCC, and traditional boilers each need their own subcate gory. Some commenters suggested that due to high moisture cont ent and high relative CO 2 emissions of lignite, lignite-fired units should have its own subcategory. Other commenters opposed the proposed standards for reconstructed units because they thou ght the BSER determination for reconstructed subpart Da units wa s inconsistent with the BSER determination for newly constructed units. These commenters stated that the EPA did not provide sufficient justification for eliminating partial ca rbon capture and sequestration (CCS). These commenters also stat ed that the reason the EPA gave for dismissing CCS in the propo sal was a lack of "sufficient information about costs." These commenters hold that the cost rationale does not apply for rec onstructed coal-fired power plants. The fact that reconstructe d units may face greater costs to comply with a CAA section 111 (b) standard*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 497 of 854 than new sources does not relieve them of their com pliance obligation. Based on a review of the comments, we have conclude d that both the proposed BSER and emission standards are a ppropriate, and we are finalizing the standards as proposed. No thing in the comments changed our view that the BSER for reconst ructed steam generating units should be based on the performance of a well operated and maintained EGU using the most efficien t generation technology available, which we have concluded is a supercritical pulverized coal (SCPC) or supercritical circulating fluidized bed (CFB) boiler for large units, and subcritical f or small units. As described at proposal, we have concluded that these standards are achievable by all the primary coal ty pes. The final standards for reconstructed utility boilers a nd IGCC units is 1,800 lb CO 2 /MWh- grossg for sources with a heat input rating of greater than 2,000 MMBtu/h and 2,000 lb CO 2 /MWh- grossg for sources with a heat input rating of 2,000 MMBtu/h o r less. While the final emission standards are based on the identified BSER, a reconstructed EGU would not nece ssarily have to rebuild the boiler to use steam temperatures and pressures that are higher than the original design. As commen ters noted, a reconstructed unit is not required to meet the stan dards if doing so is deemed to be "technologically and econo mically" infeasible. 40 CFR 60.15(b). This provision inheren tly requires*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 498 of 854 case-by-case reconstruction determinations in the l ight of considerations of economic and technological feasib ility. However, this case-by-case determination would cons ider the identified BSER (the use of the best available stea m conditions), as well as-- at a minimum-- the first four technologies the EPA considered, but rejected, as B SER for a nationwide rule. One or more of these technologies could be technically feasible and reasonable cost, depending on site specific considerations and, if so, would likely re sult in sufficient GHG reductions to comply with the applic able reconstructed standards. Finally, in some cases, eq uipment upgrades and best operating practices would result in sufficient reductions to achieve the reconstructed standards. VIII. Summary of Final Standards for Newly Construc ted , Modified, and Reconstructed Stationary Combustion Turbines This section summarizes the final applicability requirements, BSER determinations, and emission sta ndards for newly constructed , modified, and reconstructed stationary combustion turbines. We explain our rationale for theseIn addition, it also summarizes significant difference s between the proposed and final decisions in Section IX of this preamble. provisions.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 499 of 854

A. Applicability Requirements We are finalizing BSER determinations and emission standards for newly constructed , modified, and reconstructed stationary combustion turbines that (1) have a base load rating for fossil fuels greater than 260 GJ/h ( 250 MMBtu/h ) and (2) serve a generator capable of selling more than 25 M W -net of electricity to the grid. We also are finalizing app licability requirements that will exempt from the final standards (1) all stationary combustion turbines that are dedicated peaking units, dedicated non-fossil fuel-fired units (i.e., combustion turbines capable of combusting 50 percent or more non-fossil fuel) and subject to a federally enforceable permit condition restricting annual fossil fuel use to 10 percent or less of a u nit’s annual heat input capacity; (2) the large majority of indu strial CHP units , or are (i.e., CHP combustion turbines that are s ubject to a federally enforceable permit condition limitin g annual netelectric sales to the product of the unit’s net des ign efficiency multiplied by the unit’s potential outpu t, or 219,000 MWh, whichever is greater); (3) combustion turbines that are physically incapable of burning natural gas (i.e., not connected to a natural gas pipeline ),); and (4) municipal waste combustors

and commercial or industrial solid waste incinerators (units subject to subparts Eb or CCCC of this part ), as well as the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 500 of 854 large majority of industrial combined heat and powe r units from the final ). For combustion turbines subject to an emission standards. Specifically, the final emission standards do not a pplystandard, we are finalizing three subcategories: base load na tural gasfired units, non-base load natural gas-fired units, and multifuel-fired units. We use the term base load natural gas-fired units to refer to stationary combustion turbines subject to a federally enforceable permit condition limiting ann ual electric sales to the specific design efficiency of the comb ustion turbine multiplied by the unit’s potential electric output or less or restricting annual fossil fuel use to 10 pe rcent or less of a unit’s heat input capacity. Finally, the final emissionthat (1) burn over 90 percent natural gas and (2) sell e lectricity in excess of their design efficiency (not to exceed 50 percent) multiplied by their potential electric output. To b e in this subcategory, a stationary combustion turbine must e xceed the “natural gas-use criterion” on a 12-operation month rolling average and the “percentage electric sales” criteri on on both a 12-operating-month and 3-year rolling average basis . We use the term non-base load natural gas-fired units to refer to stationary combustion turbines that (1) burn over 9 0 percent natural gas and (2) have net-electric sales equal t o or below their design efficiency (not to exceed 50 percent) multiplied by*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 501 of 854 their potential electric output. These criteria are calculated on the same rolling average bases as for the base l oad subcategory. Finally, we use the term multi-fuel-fi red units to refer to stationary combustion turbines that burn 1 0 percent or more non-natural gas on a 12-operating-month rollin g average basis. We are not finalizing the proposed emission standards for modified sources and are withdrawing those standards do not apply to combined heat and power units that are sub ject to a federally enforceable permit condition limiting net -electric sales to the unit’s design efficiency multiplied by the unit’s potential output or 219,000 MWh, whichever is great er. We explain our rationale for these final decisions in Sections IX and XV of this preamble

. B. Best System of Emission Reduction We are finalizing the same BSER as proposed. For n ewly constructed, modified, and reconstructed stationary combustion turbines. The BSER is the use of modern, efficient combined cycle technology. We are finalizing BSER determinations for the thre e subcategories of stationary combustion turbines ref erred to above: base load natural gas-fired units, non-base load natural gas-fired units, and multi-fuel-fired units. For ne wly constructed and reconstructed base load natural gas -fired stationary combustion turbines, the BSER is the use of efficient*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 502 of 854 NGCC technology. For newly constructed and reconstr ucted nonbase load natural gas-fired stationary combustion t urbines, the BSER is the use of clean fuels (i.e., natural gas w ith an allowance for a small amount of distillate oil). Fo r multi-fuelfired stationary combustion turbines, the BSER is a lso the use of clean fuels (e.g., natural gas, ethylene, propan e, naphtha, jet fuel kerosene, distillate oils 1 and 2, biodies el, and landfill gas). C. Final Emission Standards For all newly constructed , modified, and reconstructed base

load natural gas-fired combustion turbines, we are final izing an emission standard of 1,000 lb CO 2 /MWh- grossg , calculated on a 12- operating - month rolling average basis. We are also finalizing an optional emission standard of 1, 080030 lb CO 2 /MWh- netn , calculated on a 12-operating - month rolling average basis . , for stationary combustion turbines in this subcategory. For newly

constructed and reconstructed non-base load natural gas-fired combustion turbines, we are finalizing a standard o f 120 lb

CO 2 /MMBtu, calculated on a 12-operating-month rolling average basis. For newly constructed and reconstructed mult i-fuel-fired combustion turbines, we are finalizing a standard o f 120 to 160

lb CO 2 /MMBtu, calculated on a 12-operating-month rolling average basis. The emission standard for multi-fuel-fired c ombustion turbines co-firing natural gas with other fuels sha ll be*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 503 of 854 determined at the end of each operating month based on the percentage of co-fired natural gas. Table 15 summar izes the subcategories, BSER determinations, and emission st andards for combustion turbines. Table 15: Combustion Turbine Subcategories and BSER

D. Significant Differences between Proposed and Fin al Combustion Turbine Provisions As shown in Tables 16 and 17 below, the proposed ru le included several general applicability criteria and two subcategorization criteria for combustion turbines. In addition to the proposed applicability and subcategorization framework, we solicited comment on a "broad applicability appr oach" that included most combustion turbines irrespective of t he actual amount of electricity sold to the grid or the actua l amount of natural gas burned (i.e., non-base load units and m ulti-fuel-

557 The emission standard for combustion turbines co-f iring natural gas with other fuels shall be determined ba sed on the amount of co-fired natural gas at the end of each o perating month. S ubcategory BSER Emission standard Base load natural gas-fired combusiton turbines Efficient NGCC 1,000 lb CO 2 /MWhg or 1,030 lb CO 2 /MWh-n Non-base load natural gas-fired combustion turbines Clean fuels 120 lb CO 2 /MMBtu

Multi fuel-fired combustion turbines Clean fuels 120 to 160 lb CO 2 /MMBtu 557*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 504 of 854 fired units, respectively). The broad applicability approach changed the proposed "percentage electric sales" an d "natural gas-use" criteria to distinguish among subcategory- specific emissions standards. Specifically, in the broad app licability approach, we solicited comment on subjecting non-ba se load units and multi-fuel-fired units to "no emissions standar d," while still including them in the general applicability. We also solicited comment on establishing a separate numeri cal standard for non-base load units. The final rule retains all of the proposed applicability criteria in some form, but m ost closely tracks the broad applicability approach by finalizi ng the percentage electric sales and natural gas-use crite ria as thresholds that distinguish among three subcategori es of combustion turbines with separate emissions standar ds. The final rule also includes exceptions to the broa d applicability approach that we solicited comment on , with some changes that are responsive to public comments. Cat egorical exceptions to the broad applicability criteria are the exclusions for CHP units, non-fossil fuel units, an d combustion turbines not able to combust natural gas. First, th e proposed applicability criteria did not include CHP units th at were constructed for the purpose of or that actually sel l one-third or less of their potential electric output or 219,0 00 MWh, whichever is greater, to the grid. The final rule e liminates the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 505 of 854 “constructed for the purpose of” and actual sales a spects of the proposal and replaces them with an exemption for CH P units that take federally enforceable permit conditions restri cting netelectric sales to a percentage of potential electri c sales based on the unit’s design efficiency or 219,000 MWh, whi chever is greater. Second, the proposed applicability criteri a did not include non-fossil fuel units that burn 10 percent or less fossil fuel on a 3-year rolling average. The final rule similarly replaces the actual fuel-use aspect of th e proposal with an exemption for non-fossil fuel units that ta ke federally enforceable permit conditions limiting fossil-fuel use to 10 percent or less of annual heat input capacity. Fina lly, the proposed applicability criteria did not include com bustion turbines that burn 90 percent or less natural gas o n a 3-year rolling average basis. In contrast, the final rule includes most fossil fuel-fired combustion turbines regardless of the amount of natural gas burned, with an exception for combus tion turbines that are not connected to natural gas pipelines. Fi nally, in response to public comments, we are not finalizing the subcategories for large and small combustion turbin es that were contained in the proposal. Instead, all base load n atural gasfired combustion turbines must meet an emission sta ndard of 1,000 lb CO 2 /MWh-g.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 506 of 854 Table 16: Proposed Applicability Criteria versus Fi nal Applicability Criteria Applicability Criteria Proposed Applicability Final Applicability Base load rating criterion Base load rating > 73 MW

(250 MMBtu/h) Base load rating > 260 GJ/h 558 (250 MMBtu/h)

Total electric sales criterion Constructed for purpose

of and actually selling > 219,000 MWh-n to the grid Ability to sell > 25 MW-n to the grid Percentage electric sales criterion Constructed for purpose

of and having actual netsales to the grid > onethird of potential electric output Changed to subcategorization criterion per broad applicability approachNatural gasuse criterion Actually burns > 90

percent natural gas • Changed to subcategorization criterion per broad applicability approach

• Exemption for combustion turbines that are not connected to a natural gas supplyFossil fueluse criterion Actually burns > 10

percent fossil fuel Exemption based on permit condition limiting amount of fossil fuel burned to ≤ 10 percent of annual heat input capacity Combined Heat and Power (CHP) exemption NA Exemption based on permit condition limiting net-electric sales to ≤ design efficiency multiplied by potential electric output, or 219,000

558 73 MW is equivalent to 260 GJ/h. We changed units to avoid potential confusion of MW referring to electric out put rather than heat input.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 507 of 854 MWh-n, whichever is greater

Non-EGU exemption Exemption for municipal

solid waste combustors and commercial or industrial solid waste incinerators Same as proposal

Table 17: Proposed Subcategories versus Final Subca tegories Subcategory Proposed

Criteria Final Criteria

Small combustion turbine subcategory Base load

rating ≤ 850 MMBtu/h NA

Large combustion turbine subcategory Base load

rating > 850 MMBtu/h NA

Base loadnatural gasfired base load combustion turbine subcategory NA • Actually burns > 90 percent natural gas

• Net-electric sales > design efficiency (not to exceed 50 percent) multiplied by potential electric output Non-base loadnatural gasfired combustion turbine subcategory NA • Actually burns > 90 percent natural gas

• Net-electric sales ≤ design efficiency (not to exceed 50 percent) multiplied by potential electric outputMulti-fuelfired combustion turbine subcategory NA Actually burns ≤ 90 percent natural gas*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 508 of 854 IX. Rationale for Final Standards for Newly Constru cted , Modified, and Reconstructed Stationary Combustion Turbines This section discusses three inter-related topics (1) the EPA’s rationale for the final applicability criteria, (2) BSER determinations , and (3) achievability of the standards forof performance for newly constructed and reconstructed stationary combustion turbines. We summarize In this section, we present a summary of what waswe proposed, relevanta selection of the significant comments we received with, and our responses, and the rationale for the final determinations. The rationale includes a discussion on for the role of simple cycle turbines in providing backup power in regions with large amo unts of intermittent renewable generation. The achievabilit y discussion explainsfinal determinations, including how the applicability criteria taken together with our BSER determination ensure that the standards are achievable by affected units. Applicability and subcategorization are closely tie d to the required emission standards, and we are carefully c onsidering them together. For example, some owners/operators m ay see an inherent value in not being subject to subpart TTTT , regardless of the requirements for that particular type of uni t under subpart TTTT, and certain exemption criteria could lead to a perverse incentive to install new units or run unit s in a way that increases CO 2 emissions above the baseline emission rate.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 509 of 854 Furthermore, the EPA recognizes that energy industr y trends have evolved, and we are adjusting our proposed approach to reflect these changes. For the proposed applicability to combustion turbin es, the EPA used the 1/3 electric sales criteria, in part becau se it already exists in regulatory context (e.g., the coal-fired EGU NSPS) and would allow for consistency between regulations. Ou r understanding at proposal was that the 1/3 electric sales criterion would essentially exclude all simple cycl e turbines and would serve to distinguish between peaking (i.e ., low capital cost, flexible, but relatively inefficient simple cycle units) and intermediate and base load combustion tu rbines (i.e., higher capital cost, less flexible, but relatively efficient combined cycle units). Based on public comments however, our understanding of the potential future roles of comb ustion turbine EGUs has evolved. The growth of generation from intermittent renewable sources has created a percei ved need for additional cycling generation that operates outside of the traditional roles of simple and combined cycle comb ustion turbines. In response, the market is developing new technologies to fill this need perceived by end users of combust ion turbines. Some manufacturers have developed high efficiency s imple cycle turbines. While these newer turbines have higher ca pital costs than older simple cycle turbine designs, they are s ignificantly*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 510 of 854 more efficient and have maintained similar flexibil ities (e.g., ability to start and change load rapidly) as previo us designs. In contrast, other manufacturers have developed fas t start flexible combined cycle units specifically to fill this role. These newer combined cycle designs have lower desig n efficiencies than base load combined cycle designs, but are able to start up more quickly to respond to rapid change s in electricity demand. Therefore, there is no longer a clear distinction between the role of simple cycle and co mbined cycle turbinesinfluenced our decision-making

. A. Applicability This section describes the proposed applicability c riteria, applicability issues we specifically solicited comm ent on, the relevant significant comments, and the final applic ability criteria. We also provide our rationale for finaliz ing an applicability determinedcriteria based strictly on design and permit restrictions and independent of rather than actual operating characteristics. Finally, we explain why the proposed percentage electric sales and natural gas-use appli cability criteria are being finalized instead as criteria to distinguish between separate subcategories of stationary combus tion turbines.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 511 of 854 1. Proposed Applicability Criteria TheIn the January 2014 proposal, we proposed fiveseveral applicability criteria for stationary combustion turbines were. Specifically, to be subject to the proposed emissio n standards, we proposed that a unit must (1) be capable of combusting more

than 73 MW ( 250 MMBtu/h ) heat input of fossil fuel; (2) be constructed for the purpose of supplying and actual ly supply more than one-third of its potential net- electric output capacity to a utility power distribution system for sale (that is, to the grid) on a 3-year rolling average; (3) b e constructed for the purpose of supplying and actually supply mo re than 219,000 MWh net-electric output to the grid on a 3- year rolling average; (4) combust over 10 percent fossil fuel on a 3-year rolling average; and (5) combust over 90 percent na tural gas on a 3-year rolling average. We proposed exempting municipal solid waste combustors and commercial and industrial soli d waste incinerators. We did not propose CO 2 standards forUnder these proposed applicability criteria, two types of stationary combustion turbines that are currently subject to criteria pol lutant standards under subpart KKKK (the combustion turbine criteria pollutant NSPS).would not have been subject to CO 2 standards. The first type was stationary combustion turbines that wereare constructed for the purpose of selling orand that actually sell*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 512 of 854 one-third or less of their potential output or 219, 000 MWh or less to the grid on a 3-year rolling average basis . (i.e., nonbase load units). The second type of unit was non-natural gasfired stationary combustion turbines (i.e., was combustion turbines that actually combust 90 percent or less n atural gas on a 3 - year rolling average basis ). Under the proposed approach, applicability with (i.e., multi-fuel-fired units). We proposed the electric sales criteria in part be cause they already exist in other regulatory contexts (e. g., the coalfired EGU criteria pollutant NSPS) and would promot e consistency between regulations. Our understanding at proposal was that the GHG NSPS could change on an annual basis depending on actual electric sales and the composition of fuel burned. percentage electric sales criterion would distinguish between non-base load units (e.g., low capital cost, flexible, but relati vely inefficient simple cycle units) and base load units (i.e., higher capital cost, less flexible, but relatively efficient combined cycle units). While the proposed applicability criteria did not explicitly exempt simple cycle combustion turbines from the emission standards , we concluded at proposal that it would, as a practical matter exclude, the vast majority of simple cycle turbines would be excluded because , they historically , simple cycle turbines have operated as peaking units and, on average,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 513 of 854 have sold less than five percent of their potential electric output on an annual basis . , well below the proposed one-third electric sales threshold. a. Solicitation of comment on applicability, genera lly We solicited comment on a range of issues related t o the general applicability of the EGU GHG NSPS to combustion turbines . In conjunction with the proposed one-third (i.e., 33.3 percent) electric sales criterionthreshold , we solicited comment

on finalizing an electric sales criteriona threshold between 20 to 40 percent of potential electric output. We also solicited comment on a variable percentage electric sales cri terion, which would allow more efficient, lower emitting turbines to run for longer periods of operation before becoming subject to the standards of performance. Under this “sliding scale ” approach,

the potential electric output or basing thepercentage electric sales criterion would be based on the net design efficiency of the combustion turbine (i.e., the sliding scale approach). Under the sliding scale approachbeing installed. In this way , more efficient combustion turbines would be able to sell a greater portion of their potential electric output , relative to compared with less efficient combustion turbines , prior to triggering before becoming subject to an emission s tandard. This approach had the electric sales criterion. benefit of*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 514 of 854 incentivizing the development and installation of m ore efficient simple cycle combustion turbines to serve peak load

. We also solicited comment on whether the percentage electric sales criterion for stationary combustion turbines should be defined on a single calendar year basis. In addition, we solicited comment on eliminating the 219,000 MWh aspect of

the total electric sales criterion for combustion turbines to eliminate any incentive for generators to install multiple, exempt, small, and less - efficient stationary combustion turbines . that would be exempt due to their lower output. We alsofurther solicited comment on whether to provide an explici t exclusionexemption for all simple cycle combustion turbines regardless of the amount of electricity sold. Finally, weWe additionally solicited comment on how to implement the proposed

actual electric sales and actual, fossil fuel - use applicability, and natural gas-use criteria given that they were

to be evaluated as 3-year rolling averages during the fi rst three years of operation, and we requested comment on appropriate monitoring, recordkeeping, and reporting requirements. We specifically solicited comment on whether these proposed requirements raiseraised implementation issues because they arewere based on source operation after construction has

occurred.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 515 of 854 We also solicited comment on excluding electricity sold during system emergencies from the calculation of p ercentage electric sales. The rationale for this exclusion wa s that simple cycle combustion turbines intended only for peaking applications might be required to operate above the proposed per centage electric sales threshold if a major power plant or transmission line became unexpectedly unavailable for an extende d period of time. The EPA proposed that this flexibility would be appropriate if the unit were called upon to run aft er all other available generating assets were already running at full load. b. Solicitation of comment on broad applicability a pproach In both the January 2014 proposal for newly constru cted EGUs and the June 2014 proposal for modified and re constructed EGUs, the EPA solicited comment on finalizing a bro ad applicability approach . instead of the proposed approach. Under the proposed approach, a stationary combustion turb ine could be an affected EGU one year, but not the next, dependi ng on the unit’s actual electric sales and the composition of fuel burned. The broad applicability approach is consistent with historical NSPS applicability approaches that are based on des ign criteria and include different emission standards for subcat egories that are distinguished by operating characteristics. Specifically, we solicited comment on whether we should completely r emove the electric sales (both the actual sales and “constructed for the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 516 of 854 purpose” criteria) and fuel and natural gas- use criteria components from the general applicability framework (that establishes the sets of sources that are subject to CAA section 111 standards).. Instead , the actualpercentage electric sales

and fuel natural gas- use thresholds would serve as subcategorization criteria for distinguishing among classes of EGUs and subcategory-specific emissions standards. Under athis broad applicability approach, the “constructed for the purpose

of” component of the percentage electric sales criteri on would be completely eliminated andso that applicability for combustion turbines would be determined only by thea unit’s base load rating (i.e., greater than 260 GJ/h ( 250 MMBtu/h ))) and theits capability to sell power to a utility distribution system (i.e., serving a generator capable of selling more than 25 MW to a utility distribution system).). In contrast to the five proposed applicability criteria, under the broad applicabili ty approach, affected units, includingnon-base load (e.g., simple cycle peaking) and multi-fuel-fired (e.g., oil-fired ) combustion turbines , would remain subject to the standard of performancerule regardless of their actual electric sales or

fuel use. The broad applicability approach is consistent with historical NSPS applicability approaches based on d esign criteria with different emission standards for subc ategories distinguished by operating characteristics. We solicited comment*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 517 of 854 on all aspects of this "broad applicability approac h," including the extent to which it would achieve theour policy objectivesobjective of assuring that a simple cycle turbine

owners and a combined cycle turbine are subject to the same standardoperators install NGCC combustion turbines if they plan

to sell more than the specified electric sales thresho ld to the grid. We also requested comment on excluding electricity sold during system emergencies as counting toward net el ectric sales for determining sales in excess of the electric sal es threshold. The rationale included that simple cycle combustion turbines intended only for peaking applications might be req uired to operate above the proposed electric sales threshold if a major power plant or transmission line is unexpectedly un available for an extended period of time. The EPA concluded that this flexibility is appropriate if the unit is called up on to run after all other available generating assets are alr eady running at full load. The definition of "system emergency" presented in the proposal was "any abnormal system condition tha t the Regional Transmission Organizations (RTO), Independ ent System Operators (ISO) or control area Administrator deter mines requires immediate automatic or manual action to pr event or limit loss of transmission facilities or generators that could adversely affect the reliability of the power syste m and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 518 of 854 therefore call for maximum generation resources to operate in the affected area, or for the specific affected fac ility to operate to avert loss of load." 2. Comments on Applicability WeThis section summarizes the comments we received comments specific to each one of the five proposed applicability criteria. We also received more general comments on the scope of the proposed framework as compared to the scope of the broad applicability approach. The comments and rationale for Comments

on applicability tofor dedicated non-fossil and CHP units (i.e., units that combust less than 10 percent fossil fuel ) and industrial CHP are discussed in Section III of this preamble. For combustion turbines, we received few specific c omments on the 10 percent fossil fuel threshold and the 90 per cent natural gas threshold. . a. Base load rating criterion Many commenters supported the general size thresholds (i.e., have a base load heat input rating greater than of 260 GJ/h ( 250 MMBtu/h and serving a generator with a capacity greater than 25 MW ) because these thresholds areit is generally consistent with the thresholdsthreshold used in states participating in the Regional Greenhouse Gas Initia tive (RGGI) and under Title IV programs. Other commenters oppos ed this thresholdthe proposed applicability thresholds and stated that*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 519 of 854 all new, modified, and reconstructed units that sel l electricity to the grid, including small EGUs , oil-fired combustion turbines, and simple cycle combustion turbines, should be

affected sourcesEGUs because unaffected unitsthey would otherwise have a competitive advantage in energy markets because these exempt unitsas they would not be required to internalize the costs of compliance . The EPA received many comments on applicability of the proposed standards to simple c ycle combustion turbines, the electric sales criteria (b oth the onethird sales relative to the potential electric outp ut and the 219,000 MWh criteria), and the broad applicability approach

. b. Total electric sales criterion Commenters noted that the 219,000 MWh total electri c sales threshold put larger combustion turbines at a compe titive disadvantage by distorting the market and could hav e the perverse impact of increasing CO 2 emissions. These commenters noted that the 219,000 MWh total electric sales thr eshold would allow combustion turbines smaller than approximatel y 80 MW to sell more than one-third of their potential electri c output, but larger, more efficient combustion turbines would st ill be restricted to selling one-third of their potential electric output to avoid triggering the NSPS. They argued th at this would result in a regulatory incentive for generators to install multiple, less-efficient combustion turbines instea d of fewer,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 520 of 854 more-efficient combustion turbines and could have t he unintended consequence of increasing CO 2 emissions. c. Percentage electric sales criterion Commenters from the power sector generally supporte d a complete exemption offor simple cycle turbines. The rationale

for theseThese commenters includedstated that simple cycle turbines are uniquely capable of achieving the ramp rates (the rate at which a power plant can increase or decreas e output) necessary to respond to emergency conditions and ho urly variations in output from intermittent renewables. Commenters noted that simple cycle combustion turbines serve a different purpose than combined cycleNGCC power blocks and that . In addition, commenters noted that electricity generat ion dispatch is based on the incremental cost to generate electr icity and that because NGCC units have a lower incremental ge neration cost than simple cycle units, economics will drive the use of combined cycleNGCC technologies over simple cycle units. However, commenters also stated that historic simpl e cycle operating data may not be representative of future system requirements as coal units retire, generation from intermittent renewable generation increases, and numerous market and regulatory drivers impact plant operations. In the absence of a complete exemption, these commenters supported ana percentage*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 521 of 854 electric sales threshold between 40 to 60 percent o f a unit’s potential electric output. Some commenters said that because the proposed perc entage electric sales criterion between 40 to 60 percent. applied over a three-year period, it would adversely affect grid reliability because operators conservatively would hedge short- term operating decisions to ensure that they have suffic ient capacity to respond to unexpected scenarios during future co mpliance periods when the demand for electricity is higher. These commenters were concerned that such compliance deci sions would drive up the cost of electricity as the most effici ent new units are taken out of service to avoid triggering the NS PS and older, less efficient units with no capacity factor limita tions are ramped up instead. Some commenters supported the sliding - scale approach (i.e., a percentage electric sales threshold based on the design efficiency of the combustion turbine) and stated that incentives for manufacturers to develop ( and end users to purchase ) higher efficienciesefficiency combustion turbines could be directionally helpful towards mitigatinghelp mitiga te concerns about a monolithic national constraint on simple cy cle capacity

factors. In contrast, others commented that fast response combined cycle-start NGCC units intended for peaking and intermediate*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 522 of 854 load applications can achieve comparable ramp rates comparable to simple cycle unitscombustion turbines, but with lower CO 2 emission rates . These commenters said that simple cycle turbines should be restricted to their historical role as true peaking units and that the proposed one-third electric sales criterion providesthreshold provided sufficient flexibility. Some commenters suggested that the one-third electric sales criterionthreshold could be reduced to 20 percent or lower without adverse impactimpacts on grid reliability. Commenters noted that a complete exclusion for simp le cycle turbines creates an opportunity to evade the standard and co uld thereby increase GHG emissions by creatingwould cre ate a regulatory incentive for generators to install and operate less efficient unaffected units compared toinstead of more efficient affected units ., thereby increasing CO 2 emissions. According to

these respondentscommenters , any applicability distinctions should be based on utilization and function rather than purpose or technology. Commenters also noted that the 219,000 MWh electric sales criteria puts larger combustion turbines at a compe titive disadvantage by distorting the market and could hav e the perverse impact of increasing GHG emissions. These commenters noted that the 219,000 MWh electric sales threshold permits combustion turbines smaller than about 80 MW to sel l more than*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 523 of 854 the proposed one-third electric sales threshold whi le larger, more efficient combustion turbines are restricted t o selling one-third of their potential electric output to avo id applicability of the proposed CO 2 standard. This creates a regulatory incentive to install multiple less effic ient combustion turbines instead of fewer more efficient combustion turbines and could have the unintended consequence of increasing GHG emissions. Commenters in general supported that net electric sales applicability the use aof 3-year rolling averageaverages instead of a single year average. However, commenters noted that the inconsistency between the 3 calendar year applicabi lity and 12- operating month compliance period results in compli ance issues. For example, a facility could burn greater than 90 percent natural gas over a 3 year period, but could burn gr eater than 10 percent distillate oil during a 12-operatng month c ompliance period with the same 3 year period. Since the CO 2 content of distillate oil is higher than natural gas, even if the facility is operating at maximum efficiency it would exceed the proposed emission standard. The inconsistency creates simila r issues-year

average for 12-operating month periods with lowthe percentage

and total electric sales , but the 3 year sales exceed the applicability threshold.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 524 of 854 In response to EPA's request for comments on whethe r the retrospective applicability requirements would crea te implementation issues, several permitting authoriti es opposed proposed applicability provisions that could change applicability determinations from year-to-year crit eria because this approach would result in compliance issues and in difficulties in determining proper pre-construction and operating permit conditions. These permitting autho rities said that in order for a source to avoid applicability o f the NSPS, the source must be subject to a federally enforceab le permit limit with associated monitoring, recordkeeping, an d reporting conditions for assessing applicability on an ongoin g basis. Other, in their view, the 3-year rolling averages w ould provide a better overall picture of normal operations. Some commenters stated that an applicability test that concludes after construction and operation have commenced is incons istent with the general purpose of an applicability test: which is intended to provide clear and predictable standards of perfo rmance for new sources that would apply when they begin operat ions. Commenters opposed the proposed retrospective appli cability criteria related to actual output supplied during a preceding compliance period a rolling 12-month or calendar-ye ar average could be severely skewed in a given year because EGUs must know what performance standards will apply to them durin g the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 525 of 854 licensing process and such criteria do not allow th e permitting authority and the public to know in advance whether or not the GHG standard applies to a proposed new unit. Commen ter said EGUs undergoing permitting should be allowed to request limits in operating permit conditions in order to remain belo w the proposed rule's applicability provisions, as thisof unforeseen or unpredicted events. They said that using a 3-yea r averaging methodology is consistent with the pre-construction permitting requirements in many federally approved SIPs and th e current approach under the Title V permitting program. Many stated a preference for the "proposed applicab ility approach" over the "broad applicability approach." These commenters did not think it was necessary to requir e combustion turbines with low electric sales or non-natural gas -fired combustion turbines to be subject to GHG standards. They stated that there is no justification for imposing burdens ome monitoring, reporting, and recordkeeping requiremen ts that would have no environmental benefit (i.e., would not reduce CO 2 emissions) since these units would be subject "no e missions standards ." In addition, would provide system operators with needed flexibility to dispatch simple cycle units a t higher than normal capacity factors. In contrast, some commenters stated

that use of the "broad applicability" approach under CA A section 111(b) proceedings is not appropriate, because the plain*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 526 of 854 language of the CAA prohibits establishment of appl icability requirements under CAA section 111 that rely on "no emissions standard" as suggested by the EPA. These commenters stated that "no emission standard" is not a "standard of perfor mance" as defined in CAA section 111(a)(1)capacity is forward -looking (e.g., payments for capacity are often made several years in advance), the 3-year averaging period provides limi ted benefit

because a "standard of performance" is defined as a "requir ement of continuous emission reduction." In contrast, man y other commenters supported inclusion of new simple cycle units within the scope of the CAA 111(b) applicability criteria so that similar, existing simple cycle units would be subje ct to the CAA 111(d) standard (to preserve the discretion of stat e planners under section 111(d)). Numerous other commenters st ated that all sources that sell electricity to the grid should be subject to the standard, including simple cycle units, because they view the utility grid as a single integrated system and that doing so may simplify development of future frameworks for c ost-effective carbon reductions from existing units, such as fram eworks based on system-wide approaches.owner/operators need to r eserve the ability to respond to unforeseen events. Multiple commenters Commenters noted that potential compliance issues could result from the inconsisten t time frame between the 3-calendar-year applicability period an d the 12-*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 527 of 854 operating-month compliance period. For example, a f acility could sell more than one-third of its potential electric output over a 3-year period, but sell less than one-third of its potential electric output during any given 12-operating-month compliance period within that 3-year period. During a 12-opera ting-month period with electric sales of less than one-third o f potential electric output, a unit could be operating for long periods at part load and have multiple starts and stops. These operating conditions have the potential to increase CO 2 emissions, regardless of the deign efficiency of the turbine. Therefore, a unit could have an emission rate in excess of the p roposed

standard. Regarding the relationship between the percentage e lectric sales criterion and system emergencies, multiple co mmenters supported exclusion of electricity generated as a r esult of a gridsystem emergency from counting towards net sales when determining applicability. One commenter stated tha t in addition to declared grid emergencies, there are other circu mstances that warrant emergency exemption under the rule, includi ng extreme market conditions, limitations on fuel supply, and reliability responses. Another commenter stated that the defini tion of "system emergency" should be defined as "any abnorm al system condition that the Regional Transmission Organizati on, Independent System Operators, or Control Area Admin istrator*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 528 of 854 determines requires immediate automatic or manual a ction to prevent a limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore calls for maximum generation resource s to operate in the affected area, or for the specific affected facility to operate to avert loss of load." The commenter said this definition is. These commenters stated that the exc lusion was appropriate because the benefits of operating these units to generate electrical power during emergency conditio ns would outweigh any adverse impacts from short-term increa ses in CO 2 emissions by units lower in the dispatch order. . One commen ter stated that, in addition to declared grid emergenci es, other circumstances might warrant emergency exemption und er the rule, including extreme market conditions, limitations on fuel supply, and reliability responses. Multiple commenters opposed the exclusion of gridsystem emergencies when calculating a source's net electricitypercentage electric sales for rule applicability purposes because CAA section 111 emission standardsNSPS must apply continuously, even during gridsystem emergencies. TheThese

commenters stated that the EPA does not have the necessary authority under the CAA to suspend the applicability of thea standard during periods of "gridsystem emergency ".. Some commenters stated that an exclusion iswould be unnecessary ,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 529 of 854

because the EPA possesses an effective mechanism to address the issue: The EPA Assistant Administrator for Enforcement is delegatedhas the authority to advise a source that the government wouldwill not sue the source for taking certain actions during an emergency. Commenters said that this enforcement discretion approach has provided prompt , flexible relief that is tailored to the needs of the particu lar emergency and the communities being served , yet and is only utilized where the relief will address the particular emergency at hand.

Commenters added that this enforcement discretion approach is consistent with the CAA’s mandate that emission limits apply continuously and provide safeguards against abuse. One commenter stated that the emergencies that the EPA mentions happen rarely and typically last for short periods, andthat the proposed applicabilitypercentage electric sales threshold would allow a source to operate at its full rated capacity for up to 2,920 hours per year without triggering NSPSapplicability , and that the potential occurrence of grid emergencies representswould represent a tiny fraction of this time. Another commenter st ated that no emergency – short of large scale destruction of power generating capacity by terrorism, war, accident, or natural disaster – cancould justify operating a peaking unit above a 10

- percent capacity factor on a 3-year rolling average

.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 530 of 854 d. Broad applicability approach In response to the EPA's request for comments on wh ether the proposed applicability requirements that retros pectively look back at actual events (i.e., the electric sale s and fuel use criteria) would create implementation issues, s everal permitting authorities opposed the provisions becau se units could be subject to coverage one year but not the n ext, resulting in compliance issues and difficulties in determining proper pre-construction and operating permit condit ions. These permitting authorities suggested that in order for a source to avoid applicability, the source should be subject t o a federally enforceable permit condition with associated monito ring, recordkeeping, and reporting conditions for assessi ng applicability on an ongoing basis. Other commenters stated that an applicability test that concludes after construc tion and operation have commenced is inconsistent with the g eneral purpose of an applicability test—to provide clear a nd predictable standards of performance for new source s that would apply when they begin operations. Some commenters opposed the proposed retrospective applicability criteria related to actual output sup plied during a preceding compliance period because EGUs must kno w what performance standards will apply to them during the licensing process, and such criteria do not allow the permitt ing authority*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 531 of 854 and the public to know in advance whether an emissi on standard applies to a proposed new unit. Other commenters sa id that EGUs undergoing permitting should be allowed to request limits in their operating permit conditions in order to remai n below the applicability thresholds, as this methodology is co nsistent with the pre-construction permitting requirements in man y federally approved SIPs and the current approach under the Ti tle V permitting program. Many commenters stated a preference for the "propos ed applicability approach" over the "broad applicabili ty approach." These commenters did not think it was necessary to require nonbase load or multi-fuel-fired combustion turbines t o be subject to emission standards. They stated that there is no justification for imposing burdensome monitoring, r eporting, and recordkeeping requirements that would have no envir onmental benefit (i.e., would not reduce CO 2 emissions) because these units would be subject to "no emissions standards ." Other commenters supported the broad applicability approa ch and stated that all new, modified, and reconstructed units tha t sell electricity to the grid, including small EGUs, oil- fired combustion turbines, and simple cycle combustion tu rbines should be affected EGUs because they would otherwise have a competitive advantage in energy markets as they would not be re quired to internalize the costs of compliance.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 532 of 854 In contrast, to preserve the discretion of state pl anners under section 111(d), many other commenters support ed the broad applicability approach and the inclusion of new sim ple cycle units within the scope of the section 111(b) emissi on standards so that similar, existing simple cycle units could be subject to the 111(d) standards. Numerous other commenters sta ted that all units that sell electricity to the grid should be s ubject to a standard, including simple cycle units, because the y view the utility grid as a single integrated system and that doing so may simplify development of future frameworks for cost- effective carbon reductions from existing units, such as fram eworks based on system-wide approaches. 3. Final Applicability Criteria and Rationale For the final rule, we are retaining the applicabil ity criteria that the unit must be capable of combustin g more than 250 MMBtu/h heat input of fossil fuel, and must ser ve a generator capable of selling more than 25 MW to the grid. While some commenters suggested we should cover smaller E GUs as well, we did not propose to cover smaller units. Consider ing this, that smaller sources emit relatively few CO 2 emissions compared to larger units, and that at this time we do not ha ve information to identify an appropriate BSER for the se units we are not finalizing any CO 2 standards for smaller units. However,

based on Based on our consideration of the comments received*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 533 of 854

related to the other four proposed applicability criteria and practical implementation issues, we are revising ho w those criteria will be implemented. First, the proposed actual electric sales relative to the potential electric o utput and the actual percent natural gas usage criteria are being finalized as applicabilityThe final applicability criteria for c ombustion turbines are generally consistent with the broad ap plicability approach on which we solicited comment. Section VII I of this preamble presents each proposed applicability crite rion together with the form of the criterion in the final rule. T he final general applicability framework includes the propos ed criteria

based on operating restriction included in a federally enforceable permit. Second, for non-CHP combustion turbines the combustion turbine's base load rating and the combu stion turbine's total electric sales capacity. The final general applicability framework also includes multiple exem ptions that are relevant to combustion turbines: combustion tur bines that are not connected to natural gas pipelines; CHP fac ilities with federally enforceable limits on total electric sale s; dedicated non-fossil units with a federally enforceable limit s on the use of fossil fuels; and municipal waste combustors and incineration units. The final applicability framework reflects multiple variations from the proposal that are responsive to public*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 534 of 854 comments. First, consistent with the broad applicab ility approach, we are finalizing the percentage electric sales and natural gas-use thresholds as subcategorization cri teria instead of as applicability criteria. In addition, for non- CHP combustion turbines, we are eliminating the proposed 219,000 MWh electric sales criterion. Next, the proposed 10 per cent fossil fuel use applicability criteria is being finalized as an exemption for non-fossil fuel-fired units that are subject to a federally enforceable permit condition limiting the use of fossil fuel.total electric sales criterion. Finally, similar towe are eliminating the proposed actual electric sales criteria, the proposed “ constructed for the purpose of selling one-third of your potential electric output applica bility criteria is being finalized as an exemption” qualif ier for dedicated peaking units that are subject to a feder ally enforceable permit limiting annualthe total and per centage electric sales . Section III described the rationale for why the EPA is criteria. We are also not finalizing GHGCO 2 standards for dedicated non-fossil fuel-fired or industrial CHP c ombustion turbines. The final applicability is generally consistent wit h the broad applicability approach we solicited comme nt on. The rationale for not finalizing CO 2 standards for dedicated nonfossil and industrial CHP units is discussed in mor e detail in Section III.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 535 of 854 The EPA agrees with commenters that the NSPS applic ability framework should be structured so that permitting a uthorities and, the regulated community , and the public can determine what standards apply prior to a facilityunit having commenced construction. ThereforeWith this in mind , the EPA has concluded that the proposed retrospectivefossil fuel-use, natural gas-use, percentage electric sales, and total electric sales applicability criteria for combustion turbines that included actual electric sales and the amount of natural gas combusted

are not practicalideal approaches , since. Because applicability determinations versebased on these criteria could change from year to year (i.e., facilitiesunits could be movingmove in and

out of applicabilitycoverage each year ). Furthermore depending on actual operating parameters), some operators wou ld not know the extent of their compliance obligations until af ter the compliance period.

Further , from a practical implementation standpoint, existing permitting rules would generally require preconstruction permitting authorities to include enfo rceable conditions limiting operations such that unaffected units wouldwill not trigger either the proposed electric sales or fuel use thresholds if they were included as general applicability criteriathresholds . Such conditions are often called “avoidance” or “synthetic minor” conditions, and these conditio ns typically*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 536 of 854 include ongoing monitoring, recordkeeping, and repo rting requirements to ensure that operations remain below a particular regulatory threshold.

The EPA following sections provide further discussion o f the final general applicability criteria and the ra tionale for changing certain proposed applicability criteria to subcategorization criteria. a. Base load rating criterion We are retaining the applicability criterion that a combustion turbine must be capable of combusting mo re than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel. We re vised the proposed 73 MW form of the base load rating criteri on to 260 GJ/h because some commenters misinterpreted the 73 MW form (which is mathematically equivalent to 250 MMBtu/h) as the electrical output rating of the generator. This cha nge is a nonsubstantive unit conversion intended to limit misin terpretation. While some commenters suggested that we expand this applicability criterion to cover smaller EGUs as we ll, we did not propose to cover smaller units. Because smaller units emit relatively few CO 2 emissions compared to larger units and because we currently do not have enough information to iden tify an appropriate BSER for these units, we are not finali zing CO 2 standards for smaller units.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 537 of 854 b. Total electric sales criterion The proposed 219,000 MWh total annual sales criteri on was based on a 25 MW unit operating at base load the en tire year (i.e., 25 MW * 8,760 h/y = 219,000 MWh/y). This cri terion was included in the original subpart Da coal-fired EGU criteria pollutant NSPS. Coal-fired EGUs tend to be much lar ger than 25 MW, and the criterion’s primary purpose was to exem pt industrial CHP facilities from the criteria pollutant NSPS. In the context of combustion turbines, however, commenters express ed concerns that the 219,000 MWh electric sales threshold would actually encourage owners and operators to install multiple, smaller, less-efficient simple cycle combustion turbines ins tead of a single, larger, more-efficient simple cycle turbine . The reason for this is that the 219,000 MWh threshold would al low smaller simple cycle combustion turbines of less than 80 MW to sell significantly more electricity relative to their po tential electric output than larger turbines. Many commente rs also indicated that having the flexibility to operate a simple cycle turbine at a higher capacity factor is important be cause it allows for capacity payments from the transmission authority. In light of these comments, we are not finalizing the 219,000 MWh total electric sales criterion for non-CHP combusti on turbines. Instead, we are finalizing a criterion that will ex empt combustion turbines that do not have the ability to sell at*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 538 of 854 least 25 MW to the grid. This approach will maintai n our goal of exempting smaller EGUs, while avoiding the perverse environmental incentives mentioned by the commenter s. As explained in Section III, however, industrial CHP u nits are sized based on demand for useful thermal output, so there is less of an incentive for owners and operators to in stall multiple smaller units. Therefore, we are maintaini ng the 219,000 MWh total electric sales criterion for CHP units. c. Percentage electric sales criterion Commenters generally opposed the proposed percentag e electric sales criterion approach because it was ba sed in part on actual electric sales, meaning applicability cou ld change periodically (i.e., a unit’s electric sales may cha nge over time, rising above and falling below the electric s ales threshold). The EPA agrees this situation is not id eal. To avoid situations in which applicability changes from year to year, we first considered two approaches using permit restri ctions. Under the first approach, a standard would apply to all s ources with permit restrictions mandating electric sales above a threshold (i.e., an approach that closely mirrors the propose d percentage electric sales criterion). Under the second approac h, a standard would apply to all sources without permit restricti ons limiting electric sales to a level below that threshold (i.e ., effectively identifying non-base load units and exc luding them*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 539 of 854 from applicability). As stated in the proposal, we did not think it was critical to include peaking and cycling unit s because peaking turbines operate less and because it would be much more expensive to lower their emission profile to that o f a combined cycle power plant or a coal-fired plant with CCS. The first approach is not practical, however, becau se new combustion turbines could avoid applicability by si mply not having a permit restriction at all. Moreover, even if a combustion turbine were subject to the restriction, it could violate its permit if it did not operate enough to sell the requisite amount of electricity. This would be nons ensical, especially because system demand would not always b e sufficient to allow all permitted units to operate above the t hreshold. Therefore, we rejected the first permitting approac h. In contrast, the second approach would be a viable method for identifying and exempting peaking units from ap plicability. However, there are multiple drawbacks to such an ap plicability approach. First, this approach would subject those turbines without a permit restricting electric sales to the final emission standards, which raises concerns as to whe ther turbines with lower actual sales could achieve the standards . For example, new NGCC units tend to dispatch prior to o lder existing units and will generally operate for extended perio ds of time near full load and sell electricity above the perce ntage*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 540 of 854 electric sales threshold. However, as NGCC units ag e, they tend to start and stop more frequently and operate at pa rt load. Yet, even if these units sell below the percentage elect ric sales threshold, they would still be affected units if th ey did not take a permit restriction. As commenters noted, par t-load operation and frequent starts and stops can reduce the efficiency of a combustion turbine. While we are co nfident that our final standards for natural gas-fired base load combustion turbines can be achieved by units serving either ba se or intermediate load, we are not as confident that aff ected NGCC units that might someday be operated as non-base lo ad units (e.g., as NSPS units age their incremental generati ng costs will tend to be higher than newer units and they will di spatch less) could achieve the standards. More importantly, however, we are concerned that us ing a permitting approach for the percentage electric sal es criterion would create problems due to the interaction betwee n 111(b) and 111(d). Under the second permitting approach we con sidered, units with low electric sales would be excluded fro m applicability, while units with high electric sales would be included. While these low-electric sales units woul d generally be simple cycle combustion turbines and the high-el ectric sales units would generally be NGCC combustion turbines, this would not always be the case. In contrast, we are finaliz ing an*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 541 of 854 applicability approach in the 111(d) emission guide lines that is based on a combustion turbine’s design characterist ics rather than electric sales. Simple cycle combustion turbin es are excluded from applicability, while NGCC units are i ncluded. As a result, the universe of sources covered by the 111( b) standards would not necessarily be the same universe of sourc es covered by the 111(d) standards. To resolve this issue, we considered whether we cou ld change the 111(d) applicability criteria to be base d on historical operation rather than design characteris tics. For example, if an existing combustion turbine had hist orically sold less than one-third of its potential output to the grid, then it would be exempt from the emission guidelines. Howev er, many existing NGCC units have historically sold less tha n this amount of electricity, meaning that they would not be subj ect to the rule. We ran into similar issues when considering o ther thresholds. For example, a percentage electric sale s threshold of 10 percent would still exempt roughly 5 percent of existing NGCC units from 111(d), while simultaneously raisin g achievability concerns with the 111(b) standard. Mo reover, even if we had finalized 111(d) applicability criteria b ased on historical operations, existing NGCC units could ha ve decided to take a permit restriction limiting their electric s ales going*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 542 of 854 forward to avoid applicability. Under any of these scenarios, our goals with respect to 111(d) would not be accom plished. To avoid this result, the EPA has concluded that it is appropriate to finalize the broad applicability app roach and set standards for combustion turbines regardless of wha t percentage of their potential electric output they sell to the grid. To accommodate the continued use of simple cycle and f ast-start NGCC combustion turbines for peaking and cycling ap plications, however, the EPA has subcategorized natural gas-fir ed combustion turbines based on a variation of the proposed perce ntage electric sales criterion. Specifically, and as expl ained in more detail in Section IX.B.2, we are finalizing the sli ding-scale approach on which we solicited comment. d. Natural gas-use criterion Similar to the proposed electric sales criteria, co mmenters generally opposed the proposed natural gas-use crit erion being based on actual operating parameters. As with the e lectric sales criteria, the EPA agrees that applicability that ca n switch periodically due to operating parameters is not ide al. The EPA

evaluated severaltwo approaches for implementing the proposed retrospective applicability criteria intent of the proposed natural gas-use criterion (i.e., to exclude non-nat ural gasfired combustion turbines) through a pre-construction and operating permit program. Forrestrictions. Under the proposed 90*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 543 of 854 percent natural gas fuel use criterion, the EPA has concluded that a comparable first approach, an emission stand ard would apply to all combustion turbines with a permit restriction would be to exempt all facilities not subject to an opera ting permit restriction requiringmandating that natural gas contribute over 90 percent of the heat input. This is not a practical restriction since (1)total heat input. 559 Under the second approach, an emission standard would apply to all c ombustion turbines without a permit restriction limiting natu ral gas use to 90 percent or less of total heat input. 560 As with the percentage electric sales criterion, the first appr oach is not practical because combustion turbines could avoid a pplicability by simply not having a permit that requires the use of more than 90 percent natural gas, even if they intend to only burn natural gas. We disregarded this approach because it would essentially provide a pathway for all NGCC units to avoid appli cability under both 111(b) and 111(d). The second approach i s problematic

559 This approach could also be written as “an emissio n standard would apply to all combustion turbines with a permi t restriction limiting the use of non-natural gas fuels to 10 per cent or less of the total heat input.” Applicability could then be avoided by simply being permitted to burn non-natural gas fuel s for more than 876 hours per year even if they actually inten ded to seldom, if ever, combust the alternate fuels. 560 This approach could also be written as “an emissio n standard would apply to all combustion turbines without perm it restrictions mandating that non-natural gas use con tribute over 10 percent or more of total heat input.”*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 544 of 854

because operating permit restrictions to improve air quali ty are typically written to limit high emission activities (e.g., limiting the use of distillate oil to 500 hours ann ually ) and), not to limit lower emitting activities ; (2) new combustion turbines could avoid applicability by simple not ha ving a permit that requires the use of over 90 percent natural ga s even if they intend to only burn natural gas; and (3) this approach is inconsistent with the objectives under CAA section 111(d) and would essentially provide a pathway for all combust ion turbines to avoid applicability under state 111(d) plans. Si milarly, finalizing an applicability requirement that exempt s combustion turbines unless they have a permit restriction limi ting nonnatural gas to 10 percent or less of the heat input (i.e., limit the use of natural gas to less than 90 percent of t he total heat input) is also problematic. Owners/operators of new combustion turbines could avoid applicability by simply being permitted to burn . This approach could lead to perverse environ mental impacts by incentivizing the use of non-natural gas fuels for , which would typically result in higher CO 2 emissions. Furthermore, the second approach would not limit th e fuels that can be burned by affected units (i.e., combustion t urbines not required to use non-natural gas fuels) and would co ntinue to cover combustion turbines even when they burn over 876 hours per year even if they actually intended to seldom, if e ver, combust*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 545 of 854 the alternate fuels. Many commenters expressed the need to maintain the ability to burn distillate oil, partic ularly during 10 percent non– natural gas curtailments. Consequentlyfuels. Because all non-natural gas fuels except H 2 have CO 2 emission rates higher than natural gas , this approach would cause similarexacerbate the concerns raised by commenters about the achievability of the 111(b) requirements when burni ng backup

fuels. In light of these issues, the EPA has concluded tha t permit restrictions are not an ideal approach to distingui shing between natural gas-fired and multi-fuel-fired combustion t urbines and are finalizing a variation of the broad applicability issues for both 111(b) and 111(d).approach. The EPA has concluded that the only waypractical approach to distinguish a non-implement the natural gas- fired combustion turbine and a natural gas-fired combustion turbineuse criterion is the to look at the turbine’s physical ability to burn any natural gas. Consistent with the intent of the rule (to establish GHG emission stand ards for natural gas-fired combustion turbines)natural gas. Therefore, we are not finalizing GHGCO 2 standards for combustion turbines that are not capable of firing any natural gas . Combustion turbines without any connection to a natural gas pipeline wo uld not be subject to any of the requirements of this rulemaki ng (i.e., not connected to a natural gas pipeline). From a practi cal*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 546 of 854 standpoint, the burners of most combustion turbines can be modified to burn natural gas, so this exemption is essentially limited to combustion turbines that are built in re mote or offshore locations without access to natural gas. C onsistent with the broad applicability approach, we are final izing standards for all other combustion turbines, but ar e subcategorizing between natural gas-fired turbines and multifuel-fired turbines. Specifically, and as explained in more detail in Section IX.B.3, we are distinguishing bet ween these classes of turbines based on whether they burn grea ter than 90 percent natural gas or not

. For the proposed one-third electric sales criterion , the EPA has concluded that a comparable permit restrict ion would be to require a combustion turbine to actually sell mo re electricity than the specified threshold. Similar t o the fuel use requirement, this is impractical because new co mbustion turbines could avoid applicability by simply not ha ving a permit restriction to actually sell more than one-third of its potential electric output. Even if a facility were subject to this restriction, a permit violation for a unit tha t does not operate enough to sell one-third of its potential e lectric output is nonsensical since system demand may not b e sufficient to allow all permitted units to operate above the s pecified threshold. The EPA has concluded that a permit rest riction*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 547 of 854 similar to the proposed one-third electric sales cr iterion would restrict sales to less than one-third of the potent ial electric output. Combustion turbines not subject to a federa lly enforceable electric sales restriction would have t o comply with the applicable standards. The EPA has concluded thi s approach is appropriate for identifying dedicated peaking units . To determine an appropriate annual electric sales thre shold to subcategorize dedicated peaking units, the EPA revi ewed operating data for existing simple cycle units from 2005 to 2014. The EPA has concluded that an appropriate ann ual electric sales threshold for dedicated peaking units should be high enough to include how the majority of simple cycle turbines have historically operated. We have concluded that based on the revised electric sales applicability criteria and p ractical implementation issues (i.e., operating permit restr ictions are written on an annual basis) permit restrictions for NSPS applicability purpose will be annual limits, as opp osed to the proposed 3 year actual net electric sales applicabi lity criteria. As stated earlier, we have concluded it is appropri ate to avoid perverse impacts resulting from the applicabi lity of this rulemaking. If we set an electric sales applicabili ty permit restriction threshold too low it could have the uni ntended impact of increasing GHG emissions. Utilities have an obligation*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 548 of 854 to provide sufficient electricity to meet system de mand regardless of specific emission standards that have been placed on individual units. By limiting certain units to l ess than onethird of their potential electric output, utilities and other developers could justify building multiple lower ca pital cost, but less efficient, simple cycle turbines combustio n turbines subject to avoidance limits below the electric sale s threshold compared to fewer higher capital cost more efficien t simple cycle combustion turbines that could meet the same demand by operating just above the proposed threshold. In eit her case, system demand would be the same and a sufficient nu mbers of combustion turbines would be built to assure suffic ient generation capacity was available, but the associat ed GHG emissions and the cost to ratepayers would be highe r for the scenario with multiple turbines operating at lower loads than the fewer more efficient units. In contrast, settin g an electric sales applicability threshold that is too high coul d leave new units with a substantial amount of potential CO 2 emissions unregulated and would reduce the number of units in cluded in 111(d) state plans. In addition, developers of new EGUs completely exempt from the 111(b) would also have a perceived benefit of not being subject to potential future re visions of 111(d) requirements. In balancing these competing f actors, the EPA has concluded that a permit restriction tied to the design*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 549 of 854 efficiency of the unit is appropriate (i.e, the sli ding scale approach). Specifically, owners/operators of new un its subject to a permit restriction limiting annual net electri c sales to the design efficiency of the unit times the potenti al electric output (e.g., limiting annual hours of operation to the design efficiency times 8,760 hours) would not be subject to the final requirements of this rulemaking. For a more detaile d discussion, see the BSER discussion. The EPA has concluded concerns raised during the pu blic comment period suggesting that the 219,000 MWh annu al sales exemption would encourage the installation of multi ple smaller, less efficient simple cycle combustion turbines ins tead of a single, more efficient and larger turbine are valid . The 219,000 MWh electric sales criterion allows simple cycle co mbustion turbines (e.g., less than 80 MW) to sell significan tly more electricity relative to the potential electric outp ut than larger turbines. Many commenters expressed that the re is an inherent value in flexibility to operate simple cyc le turbines at high capacity factors even if it is never intend ed to run at a high capacity factor. One of these factors is the ability to get capacity payments from the transmission authori ty. If we finalized the 219,000 MWh electric sales criterion for combustion turbines we would be providing a pervers e incentive to install smaller, less efficient simple cycle tur bines. We are*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 550 of 854 therefore not finalizing the 219,000 MWh annual ele ctric sales exemption for non-CHP combustion turbines. We have concluded that the emergency conditions exe mption provides flexibility to maintain system reliability and minimizes overall costs to the sector. Therefore, w e are finalizing that electricity sold during hours of op eration when the unit is called upon to operate due to a system emergency will not be counted as net electric sales. Electric sales from units that are not called upon to operate specifica lly due to the system emergency (e.g., already operating when the system emergency is declared) would be treated as normal n et electric

sales.

A. Identification of the Best System of Emission Reduc tion This section summarizes the proposed BSER for combu stion turbines, provides a summary of comments received, and the final BSER determination. For combustion turbines, we pro posed and are finalizing the use of combined cycle technology as the BSER for affected stationary combustion turbines. Combustion turbines would be required to meet an output based emission standard based on what we have concluded is an achievable st andard based on review of emission rate information from existin g natural gas-fired combined cycle units and permitted emissi on standards for recent natural gas-fired combined cycle units. 1. Proposed BSER Formatted: Heading 2, Add space between paragraphs of the same style, Line spacing: single, No bullets or numbering Formatted: Font: Not Italic*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 551 of 854 At proposal, we considered three alternatives in ev aluating the BSER for new natural gas-fired stationary combu stion turbines (1) high efficiency simple cycle aeroderiv ative turbines (2) modern, efficient NGCC units, and (3) CCS. We rejected high-efficiency simple cycle aeroderivativ e turbines as the BSER because this standalone technology does no t provide emission reductions and is more expensive compared to combined cycle technology. We rejected NGCC with CCS as the BSER because we concluded that at proposal we had insufficient i nformation to make a determination regarding the technical feasib ility of implementing CCS at combustion turbine units. In co ntrast, combined cycle units are the most common type of ne w fossil fuel-fired units being planned and built today for generating intermediate and base load power. The design is tec hnically feasible and combined cycle units are currently the lowest-cost, most efficient option for new fossil fuel-fired pow er generation. After considering the technology option s, the EPA proposed to find modern, efficient NGCC technology to be the BSER for stationary combustion turbines, and we bas ed the proposed standards on the performance of recently c onstructed natural gas-fired combined cycle units. 2. Comments Many commenters opposed the grouping of simple cycl e units and combined cycle units in the same category and e stablishing*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 552 of 854 the BSER for combustion turbines strictly based on the combined cycle mode of operation. Commenters pointed to the word "achievable" in CAA section 111(a)(1) and stated th at applying an emission standard based on combined cycle techno logy to simple cycle units is legally indefensible because simple cycle units cannot achieve emission rates as low as combi ned cycle units. Commenters also stated that under CAA sectio n 111(b)(2) the EPA may acknowledge these different functions b y completing function-specific BSER determinations and by establ ishing separate standards for these functions. Many commen ters stated that combined cycle technology should be the BSER f or base-load and intermediate-load functions, while simple cycle should be the BSER for peak-load functions. Some commenters stated that the proposed BSER analy sis for coal-fired units was inconsistent with the BSER ana lysis for natural gas-fired combustion turbines. They stated the EPA determined that use of CCS is feasible for coal-fir ed generation based on current CCS projects under development at coal-fired generating stations, but the agency did not come to the same conclusion for natural gas-fired combustion turbine s when there is an NGCC project under development that will appl y CCS to a slip stream of NGCC flue gas. Commenters further st ated that it is irrelevant that the NGCC CCS project is a partia l CCS project whereas the developmental projects for coal fired u nits are*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 553 of 854

"full-scale." These commenters stated that the EPA cannot utilize projects under development as a basis for j ustifying CCS as BSER for coal fired units and then abandon this basis for NGCC units. In addition, some commenters disagreed with the EPA’s decision to treat NGCC differently than coal- fired units on the basis that NGCC units start up and shut down more frequently than coal-fired units. The commenter sai d operating characteristics of NGCC units are not an impediment to using partial CCS, and suggested that NGCC operators could bypass the carbon capture system during startup and shutdown m odes (which are typically shorter and less intensive efforts co mpared to startup or shutdown of a coal facility) and then em ploy the carbon capture system when operating normally. Many commenters stated that CO 2 removal is just as technologically feasible and economically reasonable for an NGCC EGU as a coal-f ired EGU. These commenters referred to literature suggesting that at 40 percent removal there would be no expected differen ce in the technical requirements for either type of EGU. Some commenters referred to a DOE/NETL study that suggests the cost of CCS for NGCC is more cost effective than for coal-fired EGU s. Many commenters supported the EPA’s determination t hat NGCC with CCS technology is not BSER for newly construct ed, modified, or reconstructed combustion turbines. These comment ers agreed that there are insufficient data on costs and site- specific*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 554 of 854 constraints to conclude that CCS and EOR technologi es are available and feasible at the numerous locations in the U.S. where combined cycle projects are currently planned based on projected natural gas prices. Commenters stated tha t the limited scope of the one CCS-on-NGCC project cited in the p roposal did not reflect the costs of pipeline transport and geo logic sequestration implicit in use of this technology as a nationwide BSER technology because the slip stream of CO 2 is used at a local facility that temporarily incorporates the CO 2 into food products. Commenters also stated that CCS has not b een adequately demonstrated or proven to be commerciall y viable for NGCC units. Other commenters stated that CO 2 capture technologies do not match well with the operating flexibilities of NGCC and simple cycle units, and even if technical barriers could be overcome, application of CCS to gas-fired turbines would also be more costly (compared to applications of CCS to coa l-fired units) on a dollars-per-ton-CO 2 -captured basis because of the higher flue gas volumes (per MW of generating capac ity) and the

lower CO 2 concentrations from methane combustion in turbines compared to coal combustion in boilers.

Some commenters stated that a CCS-based standard fo r NGCC units would negatively impact the environment and t he nation’s energy needs. They also stated that CAA section 111 (a) requires the EPA to account not only for the cost of achievi ng emission*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 555 of 854 reductions, but also for the impact of BSER on ener gy requirements and the environment. The commenters ci ted Costle, where the D.C. Circuit observed that, following its analysis of adequately demonstrated emissions technology, the E PA "must exercise its discretion to choose an achievable emi ssion level which represents the best balance of economic, envi ronmental, and energy considerations." 561 The commenters also stated that requiring CCS on natural gas units would adversely affect the nation’s energy needs and the environment because i mposing partial CCS on natural gas-fired combustion turbine s would invariably delay the emission reductions that can b e obtained from new NGCC projects that displace load from olde r less efficient generating technologies. Finally, the com menters stated that since NGCC units are projected to provi de a significant share of new power generation, the EPA should recognize that requiring partial CCS on NGCC units would have proportionally higher impact on electricity prices compared to the projected number of new coal-fired generating p rojects.

These commenters concluded that the EPA cannot dete rmine that partial CCS is BSER for NGCC units without producin g severe and unacceptable consequences for the availability of a ffordable electricity in the United States. In a related comm ent, another

561 Costle, 657 F.2d at 431, n. 46.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 556 of 854 commenter said that CCS is technically feasible for gas turbine facilities, but agrees that requiring CCS for all n ew NGCC plants may hinder the construction of new, more eff icient NGCC. Instead, the commenter suggested the EPA defer a de cision on whether CCS is BSER for combustion turbine units un til the subsequent NSPS revisions. The commenter expressed concerns that the EPA’s rationale for rejecting CCS as BSER for N GCC, may be used by developers and permitting authorities as an excuse to reject CCS as Best Available Control Technology (BACT) in future New Source Review (NSR) permits. Some commenters stated that the proposed BSER analy sis should have reflected the emission rates achieved by the l atest designs deployed at advanced, state-of-the-art, NGCC instal lations.

These commenters stated that advanced NGCC technolo gies are the best system for reducing CO 2 emissions with no negative environmental impacts and no negative economic impa cts on rate

payers. B. Subcategories We are finalizing a variation of the broad applicab ility approach for combustion turbines where the percenta ge electric sales and natural gas-use criteria serve as thresho lds that distinguish between three subcategories. These subc ategories are base load natural gas-fired units, non-base load na tural gasfired units, and multi-fuel-fired units. Under the final subcategorization approach, multi-fuel-fired combus tion turbines Formatted: Font: +Body (Calibri), 11 pt, Bold, Font color: Black*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 557 of 854 are distinguished from natural gas-fired turbines i f fuels other than natural gas (e.g., distillate oil) supply 10 p ercent or more of heat input. Natural gas-fired turbines are further subcategorized as base load or non-base load units based on the percentage electric sales criterion. The percentage electric sales threshold that distinguishes base load and no n-base load units is based on the specific turbine’s design eff iciency (i.e., the sliding-scale approach). The percentage electric sales threshold is capped at 50 percent. This section describes comments we received regardi ng the proposed size-based subcategories and our rationale for not finalizing them. In addition, it describes comments we received regarding sales-based subcategories and our rationa le for adopting the sliding scale to distinguish between s ubcategories. Finally, it describes comments we received regardin g fuel-based subcategories and our rationale for adopting fuel-b ased subcategories. 1. Size-based Subcategories At proposal, the EPA identified two size-based subcategories: (1) large natural gas-fired stationa ry combustion turbines with a base load rating greater than 850 M MBtu/h and (2) small natural gas-fired stationary combustion t urbines with a base load rating of 850 MMBtu/h or less. The EPA received numerous comments regarding our proposal to subcate gorize*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 558 of 854 combustion turbines by size. Some commenters agreed with the 850 MMBtu/h cut-point between large and small units, so me suggested increasing it to 1,500 MMBtu/h, and others suggeste d eliminating size-based subcategorization altogether. For exampl e, some commenters stated that the 850 MMBtu/h cut-point wa s inappropriate because it was originally calculated based on NO X performance, not CO 2 performance. These commenters stated that 850 MMBtu/h was not a logical demarcation between m ore efficient and less efficient combustion turbines, but rather would divide the units into arbitrary size classifications. Thes e commenters suggested that 1,500 MMBtu/h would be a better cut- point because data reported to Gas Turbine World (GTW) showed tha t new combustion turbines are not currently offered with a heat input rating between 1,300 MMBtu/h and 1,800 MMBtu/h, so the higher cut-point would more accurately reflects when more efficient technologies are available. In contrast, other commenters said that differentia tion between small and large combustion turbines was not justified at all because many of the same efficiency technologie s that reduce the emission rates of larger units could be incorpo rated into smaller units (e.g., upgrades that increase the tur bine engine operating temperature, increase the turbine engine pressure ratio, or add multi-pressure steam and a steam rehe at cycle). These commenters also said that separate standards for small and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 559 of 854 large turbines would undermine the incentive for te chnology innovation, which they described as a key purpose o f the NSPS program, and that relaxing standards for smaller un its would discourage investment in more efficient technologie s, resulting in increased CO 2 emissions. These commenters recommended that the limit for both large and small units be no higher t han 1,000

lb CO 2 /MWh-g. After evaluating these comments, the EPA has decide d not to subcategorize combustion turbines based on size for several reasons. First, the heat input values listed in Gas Turbine World do not include potential heat input from duct burners. 562 Because the heat input from duct burners is necessa ry to accurately determine potential electric output, our definition of “base load rating” includes the heat input from any installed duct burners. The EPA reviewed the heat input data for existing NGCC units that has been submitted to CAMD. These d ata include the heat input from duct burners and show that mult iple NGCC power blocks have been built in the past with heat input capacities that fall within the range that commente rs suggested new turbines are not offered. Therefore, the EPA ha s concluded

562 Duct burners are optional supplemental burners loc ated in the HRSG that are used to generate additional steam. He at input to duct burners could in theory be twice that of the c ombustion turbine engine, but are more commonly sized at 10 t o 30 percent of the heat input to the combustion turbine engine.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 560 of 854 that the regulated community uses various sizes of NGCC turbines and when the heat input from duct burners is includ ed, there is no clear break between the NGCC unit sizes that cou ld distinguish between small and large units. In fact, subcategorizing by size could unduly influence the development of future NGCC offerings because manufacturers coul d be incentivized to design new products at the top end of the small subcategory to take advantage of the less stringent emission

standard. Second, commenters suggested that a cut-point of 1, 500 MMBtu/h reflects when more efficient technologies b ecome available. However, when we reviewed actual operati ng data and design data, we only found a relatively weak correl ation between turbine size and CO 2 emission rates and did not see a dramatic drop in CO 2 emission rates at 1,500 MMBtu/h. The variability o f emission rates among similar size units far exceeds any difference that could be attributed to a difference in size. In addition, the most efficient one-to-one configurati on NGCC power block with a base load rating of 1,500 MMBtu/h or l ess has a design emission rate of the 767 lb CO 2 /MWh-n (984 MMBtu/h). The most efficient one-to-one configuration NGCC power block with a base load rating just greater than 1,500 MMBtu/h ha s a design emission rate of 772 lb CO 2 /MWh-n (1,825 MMBtu/h). Because the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 561 of 854 smaller unit has a lower design emission rate than the larger unit, increasing the cut-point does not make sense. Finally, the EPA has concluded that, while certain smaller NGCC designs may be less efficient than larger NGCC designs, most existing small units have demonstrated emissio n rates below the range of emission rates on which we solicited c omment. We have concluded that the lower design efficiencies o f some small NGCC units are primarily related to model-specific design choices in both the turbine engine and HRSG, not an inherent limitation in the ability of small NGCC units to ha ve comparable efficiencies to large NGCC units. Specifically, man ufacturers could improve the efficiency of the turbine engine by using turbine engines with higher firing temperatures and high compression ratios and could improve the efficiency of the steam cycle by switching from single or double-pressure s team to triple-pressure steam and adding a reheat cycle. Fo r all of these reasons, we have decided against subcategoriz ing combustion turbines based on size. Our rationale fo r setting a single standard for small and large combustion turb ines is explained in more detail in Section IX.D.3.a below. 2. Sales-based Subcategories As described above in Section IX.A.3.c, the final applicability criteria do not include an exemption for non-CHP units based on actual electric sales or permit rest rictions*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 562 of 854 limiting the amount of electricity that can be sold . Instead, we are finalizing the percentage electric sales criter ion as a threshold to distinguish between two natural gas-fi red combustion turbine subcategories. The industry uses a number of terms to describe combustion turbines with differen t operating characteristics based on electric sales (e.g., capa city factors). Combustion turbines that operate at near- steady, high loads are generally referred to as "base load" or “ intermediate load” units, depending on how many hours the units operate annually. Combustion turbines that operate continuo usly with variable loads that correspond to variable demand a re referred to as "load following" or "cycling" units. Combusti on turbines that only operate during periods with the highest e lectricity demand are referred to as "peaking" units. However, it is difficult to characterize a particular unit using j ust one of these terms. For example, a particular unit may ser ve as a load following unit during winter, but serve as a base l oad unit during summer. In addition, none of these terms has a precise universal definition. In this preamble, we refer to the subcategory of combustion turbines that sell a sign ificant portion of their potential electric output as "base load units." This subcategory includes units that would colloqui ally be referred to as base load units, as well as some int ermediate load and load following units. We refer to all othe r units as*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 563 of 854 “non-base load units.” This subcategory includes pe aking units, as well as some load following and intermediate loa d units. The threshold that distinguishes between these two subc ategories is determined by a unit’s design efficiency and varies from 33 to 50 percent, hence the term “slide scale” approach. Numerous commenters supported three sales-based subcategories for peaking, intermediate load, and b ase load units. These commenters said that each subcategory should be distinguished by annual hours of operation and that each should have a different BSER and emission standard. Other commenters opposed the tiered approach. These commenters stated that advanced NGCC technologies are capable of achieving emission rates that are 8 percent lower than conventional NG CC facilities. Commenters said that the majority of ex isting sources that do not deploy these advanced technolog ies are currently able to meet the standard, and commenters said that the proposal failed to explain why these lower-emit ting advanced technologies that are more than adequately demonstr ated were not

selected as the BSER. 3. Identification of BSER As stated in the proposal, combined cycle units hav e both lower GHG emissions and a lower cost of electricity than simple cycle turbine facilities when operated as intermedi ate and base load EGUs. Therefore, the use of a combined cycle t echnology*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 564 of 854 would be BSER for higher capacity factor stationary combustion turbines. The EPA refined the LCOE costing approach used at proposal to compare the cost effectiveness of simpl e cycle combustion turbines compared to combined cycle comb ustion turbines by adding costs and efficiency impacts due to frequent cycling. Even accounting for these costs, combined cycle technology results in a lower cost of electricity, compared to a simple cycle unit, when electric sales exceed one-t hird of the potential electric output. Furthermore, we have con cluded that high efficiency simple cycle turbine technology is a subcomponent of the selected BSER. Recent combined cyc le installations have included dampers that allow the associated combustion turbine to operate in either combined cy cle mode or simple cycle mode. The selected BSER and emission s tandard is compatible with the construction of new, modified, and reconstructed bi-modal units with dampers that allo w the new source to operate in either combined cycle mode or in simple cycle mode; therefore the use of combined cycle tec hnology is BSER for periods of intermediate and base load oper ation. However, for dedicated peaking applications highly efficient simple cycle technology alone is considered the BSE R. The EPA has reviewed the comments on the use of CC S for combined cycle facilities and has concluded that ev en if CCS is demonstrated as a technical and reasonable cost opt ion for*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 565 of 854 combined cycle units on an individual basis, it wou ld not qualify as BSER based on the nationwide economic im pacts. Therefore, the EPA is not making a determination as to the technical availability or individual cost reasonabl eness of CCS for new combined cycle units. Nearly all new fossil fuel-fired EGUs being constructed today are using combined cyc le technology for generating intermediate and base load power and requiring partial CCS on these units would result in unreason able nationwide impacts. The EPA has concluded that advanced combined cycle technology is simply incremental improvements to tr aditional combined cycle designs and not a unique technology and therefore cannot be the BSER. The emission rates achieved by these technologies were included within the data set of n ewer combined cycle designs used for establishing the standard. I n addition, review of the operating data for combined cycle pow er blocks installed since 2000 indicates that the mode of ope ration in response to system demand (e.g., base load or inter mediate load and capacity factor in general) impacts achieved ef ficiencies to a large enough extent that we cannot evaluate the i mpact of particular subcomponents used within the power bloc k. So a conventional combined cycle power block located in a region of the country where system demand requires the power block to run continuously at base load can achieve higher effici encies than*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 566 of 854 an advanced combined cycle power block located in a region where system demand requires the power block to cycle on and off to match system demand. For this reason, our data set included a large population of technologies and load condition s to ensure that new combined cycle power blocks can achieve th e section 111 standard in all regions of the country. 4. Identification of Applicability Based on Permitt ed Electric

Sales At proposal, we assumed all combustion turbines ope rating above the proposed 1/3 electric sales criterion wou ld be able to comply with a standard consistent with the performa nce of recently constructed combined cycle facilities. How ever, as described in the applicability section, our underst anding of the future role of combustion turbine EGUs has evolved. At this time however, we do not have sufficient information to e stablish an appropriate output-based emission rate for combusti on turbines operating with operations that span this entire cat egory. Therefore, our applicability approach is to use a s liding scale trigger. With the sliding scale approach, the trigg er for applicability for the combined cycle standard depen ds on the design efficiency of the unit. Affected units subje ct to federally enforceable permit restrictions limiting operating below the electric sales threshold would not be req uired to comply with the requirements included in subpart TT TT. This both*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 567 of 854 encourages the installation of the most efficient t echnologies intended for limited operation by giving the most e fficient units the flexibility to sell more electricity and minimizes emissions for higher capacity factor units by requi ring them to comply with the requirements of subpart TTTT. As discussed previously, the proposed percent actua l electric sales relative to the potential electric o utput criterion is being finalized as a permit restrictio n applicability criteria. Based on the concerns raise d in the comments about the impact of intermittent renewable generation (e.g., wind and solar) on the operation of simple c ycle turbines, the EPA has done additional analysis. Fir st, we evaluated the percent sales applicability criterion in greater detail to get a more accurate picture of how many s imple cycles would have met the electric sales applicability cri terion based on historical operation. We also examined the opera tion of simple turbines in regions with relatively large am ounts of wind and solar generation. In the proposal, the EPA estimated the number of si mple cycle turbines that would have met the proposed app licability based on the number of simple cycle turbines that o perated over 2,920 hours in any year. However, this was a simpli fication of the one-third actual electric sales criteria and ov erestimated the number of potentially impacted simple cycle tur bines in two*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 568 of 854 ways. First, the 2,920 hours simplification assumes operation at full load. However, the typical duty cycle (average capacity factor while operating) of simple cycle turbines is approximately 70 percent. Therefore, simple cycle t urbines can operate in excess of 2,920 hours and still not be s elling onethird of their potential electric output. Historica lly, only 10 of the 1,939 existing simple cycle turbines have in dividual years where sales exceeded one-third of their poten tial electric output. Second, the proposed one-third electric sal es applicability criterion was on a 3-year rolling ave rage basis. Using 3-year rolling average basis, the number of e xisting simple cycle turbines that historically sold enough electricity to meet the proposed one-third electric sales appli cability is only two. We used information reported to the Energy Informa tion Administration (EIA) to determine the impact ofThes e commenters said that separate standards for different operatin g conditions would be complicated to implement and enforce, whil e providing few benefits. These commenters said that a tiered a pproach could also have the unintended consequence of encouraging less efficient technologies because it would create a re gulatory incentive to install lower-capital-cost, less-effic ient units that would operate under the percentage electric sa les threshold*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 569 of 854 instead of higher-capital-cost, more-efficient unit s that would operate above the threshold. After evaluating these comments, the EPA has conclu ded that it is appropriate to adopt a two-tiered subcategori zation approach based on a percentage electric sales thres hold to distinguish between non-base load and base load uni ts. While we agree with commenters that separate standards for p eaking, intermediate, and base load units is attractive on the surface, we ultimately concluded that a three-tiered approac h is not appropriate for several reasons. First, the increas ed generation from renewable sources that is anticipated in the c oming years makes it very difficult to determine appropriate th resholds to distinguish among peaking, intermediate, and base l oad subcategories. Indeed, the boundaries between these demandserving functions may blur or shift in the years to come. The task is further complicated because each transmissi on region has a different mix of generation technologies and load profiles with different peaking, intermediate, and base load requirements. Second, there are only two distinct combustion turb ine technologies – simple cycle units and NGCC units. I n theory, the BSER for the intermediate load subcategory could be based on high-efficiency simple cycle units or fast-start NG CC units, but these are variations on traditional technologies an d not*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 570 of 854 necessarily distinct. Moreover, we do not have spec ific cost information on either high-efficiency simple cycle turbines or fast-start NGCC units, so our ability to make cost comparisons to conventional designs is limited. Finally, even if we could identify appropriate sale s thresholds to distinguish between peaking, intermed iate load, and base load subcategories, we do not have suffici ent information to establish a meaningful output-based standard for an intermediate load subcategory at this time. In t he transition zone from peaking to base load operation (i.e., cyc ling and intermediate load), combustion turbines may have si milar electric sales, but very different operating charac teristics. For example, despite having similar sales, one unit might have relatively steady operation for a short period of t ime, while another could have variable operation throughout th e entire year. The latter unit would likely have a higher CO 2 emission rate. For all of these reasons, the EPA has conclud ed that we do not have sufficient information at this time to est ablish three sales-based subcategories. Instead, as we explained above, we are finalizing t wo sales-based subcategories. To determine an appropri ate threshold to distinguish between base load and non-base load units, the EPA considered the important characteristics of the combustion turbines that serve each type of demand. For non-ba se load*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 571 of 854 units, low capital costs and the ability to start, stop, and change load quickly are key. Simple cycle combustio n turbines meet these criteria and thus serve the bulk of peak demand. In contrast, for base load units, efficiency is the ke y consideration, while capital costs and the ability to start and stop quickly are less important. While NGCC units h ave relatively high capital costs and are less flexible operationally, they are more efficient than simple cycle units. NGCC units recover the exhaust heat from the combus tion turbine with a HRSG to power a steam turbine, which reduces fuel use and

CO 2 emissions by approximately one-third compared to a simple cycle design. Consequently, base load units use NGC C technology. Because simple cycle turbines have historically bee n non-base load units, we have concluded that it is appropriat e to distinguish between the non-base load and base load subcategories in a way that recognizes the distinct roles of the different turbine designs on the market. The challenge, however, is setting a threshold that will not distort the market. The future distinction betw een non-base load and base load units is unclear. For example, s ome commenters indicated that increased generation from intermittent renewable sources has created a perceived need for additional cycling and load following generation that will ope rate between the traditional roles of peaking and base load unit s. To fulfill*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 572 of 854 this perceived need, some manufacturers have develo ped highefficiency simple cycle turbines. These high-effici ency turbines have higher capital costs than traditional simple c ycle turbine designs, but maintain similar flexibilities, such a s the ability to start, stop, and change load rapidly. Other manu facturers have developed fast-start NGCC turbines to fill the same role. These newer NGCC designs have lower design efficien cies than NGCC designs intended to only operate as base load units, but are able to start up more quickly to respond to rap id changes in electricity demand. As a result of these new techno logical developments, both high-efficiency simple cycle and fast-start NGCC units can be used for traditional peaking appl ications, as well as for higher capacity applications, such as s upporting the growth of intermittent renewable generation. With the changing electric sector in mind, we set o ut to identify an appropriate percentage electric sales t hreshold to distinguish between non-base load and base load nat ural gasfired units. Two factors were of primary importance to our decision. First, the threshold needed to be high en ough to address commenters’ concerns about the need to main tain flexibility for simple cycle units to support the g rowth of intermittent renewable generation. Second, the thre shold needed to be low enough to avoid creating a perverse incen tive for owners and operators to avoid the base load subcate gory by*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 573 of 854 installing multiple, less efficient turbines instea d of fewer, more efficient turbines. To determine the potential impact of intermittent renewable generation on the operation of simple cycle turbines. The EIA providesunits, we examined the average electric sal es of simple cycle turbines in the lower 48 states between 2005 and 2014 using information submitted to CAMD. We combined th is data on thewith information reported to the EIA on total in-state electricity generation, including wind and solar, f rom 2008 through 2014. Interstate flow of electricity is available from 2008 through 2012. California, Texas, and We focuse d on data

from the Southwest Power Pool (data approximated by EGUs in Nebraska, Kansas, and Oklahoma ) all had increases for the percent of wind and solar electricity generated in- state and percent of total electric ), Texas, and California. All of these regions have relatively large amounts of generation from wind

and solar from 2008 through and experienced increases in the portion of total electric generation provided by wi nd and solar during the 2008- 2014 . To determine the observed impact of the increased generation from intermittent renewable so urces, the EPA reviewed data submitted for simple cycle turbin es to the EPA’s Clean Air Markets Division (CAMD) over the sa me time period.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 574 of 854

a. Southwest Power Pool

The percentportion of in-state generation from wind and solar in the Southwest Power Pool increased from 3 to 16 percent between 2008 and 2014. The average growth rate of w ind and solar was 28 percent, while overall electricity demand gr ew 1 percent annually on average. Based on statements in some of the comments, we would expectexpected to see a large change in the operation of simple cycle turbines in this region. However, the

average percent electric sales compared to the potential electric output from simple cycle turbines only increased at an annual rate of 1.7 percent, and remained essentiall y unchanged at 3 percent of potential electric salesoutput between 2008 and 2014. Overall,Total generation from simple cycle turbines in the

Southwest Power Pool increased slightly more , at an annual rate of 2.5 percent, resulting from which was the result of additional simple cycle capacity being in line with what was expected dueadded to overalladdress increased electricity

demand . The lack of significant change in the operation o f simple cycle turbines in this region could be expla ined by the relatively large amount of exported power. If most of the intermittent power was being exported, the intermit tent nature of the power would primarily impact other transmiss ion regions. An alternate explanation is that other generating a ssets are flexible enough to respond to the intermittent natu re of wind*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 575 of 854 generation and that simple cycle turbines are not n ecessary to backup wind and solar generating assets to the degr ee some commenters suggested. If this were the case, then n ew simple cycle turbine will primarily continue to fill their historical role as peaking units and flexible combined cycle u nits will provide the primary backup capacity for new wind an d solar generating assets

. This lack of a significant change in the operation of simple cycle turbines could be explained by the Sou thwest Power Pool’s relatively large amount of exported power. I f most of the region’s renewable generation was being exported, t he intermittent nature of this power would primarily i mpact other transmission regions. An alternate explanation, how ever, is that other generating assets are flexible enough to resp ond to the intermittent nature of wind and solar generation an d that simple cycle turbines are not necessary to back up these a ssets to the degree some commenters suggested. If this is the ca se, then new simple cycle turbines may primarily continue to fil l their historical role as peaking units going forward, whi le other technologies, such as fast-start NGCC units, may pr ovide the primary backup capacity for new wind and solar.

b. Texas

The percentportion of in-state generation from wind and solar in Texas increased from 4 to 9 percent betwee n 2008 and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 576 of 854 2014. The average growth rate of wind and solar was 13 percent, while the overall demand grew at an average rate of 2 percent annually. However, similarSimilar to the Southwest Power Pool,

the overall percent of average electric sales relative to the potential electric output fromof simple cycle turbines has remained relatively unchanged. AverageIn fact, the average electric sales relative to potential electric outputof these turbines decreased at an annual rate of 1.1 percent . Total generation from simple cycle turbines increased at an annual

rate of 0.9 percent. However, the overall generation from s imple cycle combustion turbines increased at an annual ra te of 6.6 percent, resulting fromhowever, due to simple cycle capacity additions occurringthat occurred at approximately four times

whatthe rate one would be expectedexpect from the growth in

overall demand.

The most likely technologies to back up intermittent renewable generation have low incremental generatin g costs and can start up and stop quickly. Highly efficient sim ple cycle units meet these criteria. As such, the EPA has concluded that

the most likelyefficient simple cycle turbines in a given region are the most likely to support intermittent renewable generation are the most efficient simple cycle combustion turb ines installed in the particular transmission region. Fo cusing on these simple cycle turbines will address concerns r aised by*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 577 of 854 commenters about the future percentage electric sal es of highly efficient simple cycle turbines and give an indicat ion of the impact of increased renewable generation on non-bas e load units intended to backup wind and solar . There are two highly efficient intercooled simple cycle turbines install ed in Texas. These two combustion turbines sell an average of 10 percent of their potential electric output annually, compared to an average of 3 percent for the remaining simple cycle turbine s. No simple cycle turbine in Texas sold more than 25 percent of its potential electric salesoutput annually. ThisThe rapid growth in simple cycle turbine capacity , but not overall capacity factors, could indicate that the additional generation assets

are necessary to provideproviding firm capacity for intermittent generation sources such as wind and solar, but basedthat capacity is infrequently required. Based on the data those, even highly efficient simple cycle turbines are expected to continue operating as they have historically, and sell less than onethird of their potential electric output. c. California

The percentportion of in-state generation from wind and solar in California increased from 3 to 11 percent between 2008 and 2014. The average growth rate of wind and solar was 25 percent, while overall demand has remained stable. The operation of simple cycle turbines in California has changed more*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 578 of 854 significantly than in the other evaluated regions. The average electric sales from simple cycle turbines increased from 5.1 to 5.9 percent, an annual rate increase of 4.5 percent

. As in Texas, considerable additional simple cycle capacit y has been added in recent years. The averagetotal capacity of simple cycle turbines is increasing at 15 percent annually even though overall demand has remained relatively steady. In a ddition, the newest simple cycle turbines are operating at highe r capacity factors than the existing fleet of simple cycle tur bines ., resulting in an average increase in generation from simple cycle turbines of 21 percent. Many of the new additions are intercooled simple cycle turbines that can bemay have been installed with the specific intent to back up wind and solar generation. The annual electric sales relative to the potential electric output for the intercooled turbines range from 3 to 25 percent, with a 7 percent average. No simple cycle turbines in California have sold more than one-third of their p otential electric output on an annual basis. Based on historical amounts of intermittent generat ion, the proposed one-third actualThe average electric sales for the intercooled turbines ranged from 3 to 25 percent, w ith a 7 percent average. No simple cycle turbines in Califo rnia have sold more than one-third of their potential electri c output on an annual basis. The operation of simple cycle turb ines that*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 579 of 854 existed prior to 2008 has not changed significantly . Average electric sales for these turbines increased at an a nnual rate of 0.1 percent. This indicates that support for new re newable generation is being provided by new units and not b y the installed base of simple cycle units. These units a re still serving their historical role of providing power du ring peak periods of demand. Based on our data analysis, the proposed one-third electric sales threshold would appear to offer sufficient op erational flexibility for new simple cycle turbines. Existing combined cycleNGCC units , other generation assets, and demand - response programs are currently provingproviding adequate backup to intermittent renewable generation. In the future, however, existing combined cycle facilitiesNGCC units will likely provide base load power and operate at higher capacity factors. They will therefore be less available to provide backup power for intermittent generation. In addition, the percentamount of power generated fromby intermittent sources is expected to increase in the future. Both of these factors could require add itional flexibility from the remaining generation sources t o maintain grid reliability. Even though fast - start combined cycle technologiesNGCC units , reciprocating internal combustion engines, energy storage technologies, and demand - response programs are promising*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 580 of 854 technologies for providing backup power for renewab le generation, none of them historically have been dep loyed in sufficient capacity to provide the potential necessary capacity needed in the future to facilitate the continued growth of renewable generation. While we anticipate that stat e and federally issued permits for new electric generatin g sources will consider the GHGCO 2 benefits of these technologies compared to simple cycle turbines, the EPA has concluded at this time

that it is appropriate to finalize an NSPSa percentage electric

sales threshold that provides additional flexibility for new combustionsimple cycle turbines intended to run at lower capacity factors. Specifically, new combustion turb ines can avoid the requirements of subpart TTTT by requestin g a federally enforceable permit restriction to sell the design e fficiency times the potential electric output electricity on an annual basis. . The EPA considered multiple options for extending flexibility for simple cycle turbines. UltimatelySp ecifically ,

we have concluded that a triggerpercentage electric sales

threshold based on thea unit’s design net efficiency at standard conditions is appropriate. The electric sales trigger for applicability of the combined cycle based standard would be based This is the sliding-scale approach on the design net efficiency of the facility. The EPA has concludedwh ich we*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 581 of 854 solicited comment. Several commenters supported this approach because it provides sufficient operational flexibility for new simple cycle and fast-start NGCC combustion turbines , even with increased future use. In addition, even though the historical electric sales of simple cycle turbines is less tha n 5 percent, this net efficiency trigger approach has the impact of promoting and simultaneously promotes the installation of the most efficient generating technologies since applicability and operational flexibility would be linked directly to the efficiency of the devices. The . By allowing more e fficient turbines to sell more electricity before becoming s ubject to the standard for the base load subcategory, the sliding scale should reduce the perverse incentive for owners and operat ors to install more lower-capital-cost, less-efficient uni ts instead of fewer higher-capital-cost, more-efficient units. At the same time, the sliding scale should incentivize turbine manufacturers to design higher efficiency simple cycle turbines t hat owners and operators can run more frequently.

The net design net efficiencies for currently available potentially impacted aeroderivative simple cycle combustion turbines range from approximately 32 percent for sm aller designs to 39 percent for the largest intercooled designs. The net design efficiencies of industrial frame units range from 30 percent for smaller designs to 36 percent for the l argest*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 582 of 854 unitsdesigns . These efficiency values follow the methodology th e EPA has historically used and are based on the high er heating value (HHV) of the fuel. In contrast, combustion tu rbine vendors in the United StatesU.S. often quote efficiencies based on the lower heating value (LHV) of the fuel. The LHV of a fuel is determined by subtracting the heat of vaporization of water vapor generated during combustion of fuel from the higher heating value.HHV. For natural gas, the LHV is approximately 10 percent lower thatthan the HHV. Therefore, the corresponding LHV efficiency ranges would be 35 to 44 percent for aeroderativeaeroderivative designs and 33 to 40 percent for frame designs. Based We considered basing the percentage electric sales threshold on commentsboth the HHV and LHV. The EPA typically uses the HHV, but in light of comment ers’ concerns regarding uncertainty in the operation of non-base load units in

the future , we opted to be conservative and use the LHV efficiency.

We anticipate the aeroderativethat high-efficiency simple cycle and fast-start NGCC turbines will make up the majority of

new combustion turbinescapacity intended for limited use (i.e., peaking)non-base load applications. Based on the sliding - scale applicability approach, owners / and operators of new simple cycle combustion turbines could elect to request a federally enforceable permit limiting annual sales will be ab le to sell*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 583 of 854

between 3235 to 3944 percent of the turbine’s potential electric output to avoid complying with the standards in this rule mkaing. Based on historical operation of simple cycle turbi nes,. Our analysis showed that 99.5 percent do of existing simple cycle turbines have not sellsold more than one-third of their potential electric output on an annual basis. Therefore, the majority of new simple cycle applications could tak e a permit restriction without impacting how they would operat e or what combustion turbine they would select. In addition, 99.9 percent

of existing simple cycle turbines operate lesshave not sold more than 36 percent on an annual basis. Owners/operators of new simple cycle combustion turbines would still have m ultiple technology options available to them to accommodate this amount of operation. of their potential electric output on an annual basis. The two simple cycle turbines that exceeded the 36 percent threshold had annual electric sales of 39 and 45 percent and are located in Montana and New York , respectively. As noted earlier, the most efficient simple cycle turbine currently available is 3944 percent efficient and would accommodate operation of the operations at the Montana facility. The only existing simple cycle turbine that exceeded the maximum allowable percentage electric sales threshold permit restriction,of 44 percent, which is based on current simple cycle designs, sold an abnormally high amount of el ectricity in*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 584 of 854 2014. It is possible that this unit was operating u nder emergency conditions and. As explained below, the incremental generation due to the emergency would not have been counted as netagainst the percentage electric sales for applicability purposes. Regardless, as described earlier, for com bustion turbines operating above this threshold it is cost effective and the BSER is the additional of heat recovery to the turbine exhaust. Since the definition of stationary combust ion turbine includes both simple and combined cycle units, we a re capping the maximum permit restriction to 40 percent of the potential electric output. Combined cycle unit design efficie ncies often exceed 50 percent. Without this restriction many ex isting combined cycle units could request permit limitatio ns to avoid applicability with the 111(d) requirements. .

R. C. Achievability of the Final Standards We are capping the percentage electric sales threshold at 50 percent of potential electric output for multipl e reasons. First, NGCC emission rates are relatively steady ab ove 50 percent electric sales, so there is no reason that a NGCC unit with sales greater than this amount should not have to comply with the output-based standard for the base load su bcategory. Second, the net design efficiency of the fast-start NGCC units intended for peaking and intermediate load applicat ions is 49 percent. As described earlier, this technology can serve the Formatted: FR Body Text DS, Line spacing: single, Numbered + Level: 1 + Numbering Style: A, B, C, ... + Start at: 1 + Alignment: Left + Aligned at: 0" + Indent at: 0.3", No widow/orphan control Formatted: Font: Not Italic*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 585 of 854 same purpose as high-efficiency simple cycle turbin es. If we were to set a cap any lower than 50 percent, it cou ld create a disincentive for owners and operators to choose thi s promising new technology. Finally, the EPA solicited comment on excluding ele ctricity sold during system emergencies from counting toward s the percentage electric sales threshold. After consider ing the comments, we have concluded at proposal that, for a that this exclusion is necessary to provide flexibility, main tain system reliability, and minimize overall costs to the sect or. We disagree with commenters that suggested that the EP A’s existing enforcement discretion would be a viable alternativ e. An enforcement discretion-based approach would not pro vide certainty to the regulated community, public, and r egulatory authorities on the applicability of the emission st andards, which is a primary reason why we are finalizing the broad applicability approach. Moreover, system emergencie s are defined events, so commenters’ fears that the exclusion wil l be subject to abuse are overstated. Therefore, electricity sol d during hours of operation when a unit is called upon to op erate due to a system emergency will not be counted toward the p ercentage electric sales threshold. However, electricity sold by units that are not called upon to operate due to a system emergency (e.g., units already operating when the system emer gency is*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 586 of 854 declared) will be counted toward the percentage ele ctric sales

threshold. In summary, the EPA is finalizing the percentage el ectric sales criterion as a threshold to distinguish betwe en two natural gas-fired combustion turbine subcategories. Specifically, all units that have electric sales gr eater than their net LHV design efficiencies (as a percentage of potential electric output) are base load units. All units tha t have electric sales less than or equal to their net LHV design efficiencies are non-base load units. We are cappin g the percentage electric sales threshold at 50 percent o f potential electric output. This sliding-scale approach will l imit the operation of the least efficient units, provide fle xibility for renewable energy growth, and incentivize the develo pment of more efficient simple cycle units. 3. Fuel-based Subcategories As described in Section IX.A.3.d, we are finalizing a version of the broad applicability approach. Under the broad applicability approach, the EPA solicited comment o n a subcategorization approach based in part on natural gas-use. We received few comments on this issue. One of the com ments we did receive was that combustion turbines that burn fuel s other than natural gas have higher CO 2 emissions due to the higher relative*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 587 of 854 carbon content of alternate fuels. Besides hydrogen , 563 natural gas has the lowest CO 2 emission rate on a lb/MMBtu basis of any fossil fuel. Therefore, burning fuels other than na tural gas will result in a higher CO 2 emission rate. We interpret this comment to mean that, if we were to subcategorize b ased on fuel use, turbines that burn non-natural gas fuels shoul d receive a less stringent emission standard. For the reasons described in the applicability sect ion, we have decided to set emission standards for all comb ustion turbines capable of burning natural gas, regardless of the actual fuel burned, to avoid the practical problems that would have arisen under the proposed approach. However, a s commenters explained, multi-fuel-fired combustion turbines can not achieve the emission standards achieved by natural-gas fire d turbines. For this reason, it would not be reasonable to requ ire affected EGUs to comply with a standard based on the use of natural gas during periods when significant quantities of non-n atural gas fuels are being burned. If we did not subcategorize , owners and operators would not be able to combust other fuels in their turbines, including process gas, blast furnace gas, and petroleum-based liquid wastes, which might otherwis e be wasted.

563 Hydrogen would only be considered a fossil fuel if it were derived for the purpose of creating useful heat fro m coal, oil, or natural gas.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 588 of 854 In addition, without the ability to burn backup fue ls during natural gas curtailments, grid reliability could be jeopardized. Therefore, we are finalizing a separate fuel-based subcategory for multi-fuel-fired combustion turbines. To distin guish between this subcategory and the natural gas-fired subcateg ories, we are using the same threshold as proposed. Specifically, combustion turbines that burn ninety percent or less natural g as on a 12- operating-month rolling average basis will be inclu ded in this subcategory and subject to a separate emission stan dard, which is discussed in Section IX.D.3.d.

C. Identification of the Best System of Emission Reduc tion This section summarizes the EPA’s proposed BSER determinations for stationary combustion turbines, provides a summary of the comments we received, and explains o ur final BSER determinations for each of the three subcategories we are now finalizing. For natural gas-fired stationary combus tion turbines operating as base load units, we proposed and are f inalizing the use of NGCC technology as the BSER. For the other t wo subcategories of affected combustion turbines – non -base load natural gas-fired combustion turbines and multi-fue l-fired combustion turbines – we are finalizing the use of clean fuels

as the BSER.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 589 of 854 1. Proposed BSER We considered three alternatives in evaluating the BSER for base load natural gas-fired combustion turbines: (1 ) partial CCS, (2) high-efficiency simple cycle aeroderivativ e turbines, and (3) modern, efficient NGCC turbines. We rejecte d partial CCS as the BSER because we concluded that we did not ha ve sufficient information to determine whether implementing CCS f or combustion turbines was technically feasible. We rejected high -efficiency simple cycle aeroderivative turbines as the BSER be cause this standalone technology does not provide emission red uctions and generally is more expensive than NGCC technology fo r base load applications. In contrast, NGCC is the most common type of new fossil fuel-fired EGU currently being planned and b uilt for generating base load power. NGCC is technically fea sible, and NGCC units are currently the lowest-cost, most effi cient option for new base load fossil fuel-fired power generatio n. After considering the options, the EPA proposed to find t hat modern, efficient NGCC technology is the BSER for base load natural gasfired combustion turbines. For non-base load natural gas-fired units and multi -fuelfired units, we did not propose a specific BSER or associated numeric emission standards, but instead solicited c omment on these issues.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 590 of 854 2. Comments on the Proposed BSER for Base Load Natu ral Gas-Fired Combustion Turbines This section summarizes the differing comments subm itted on the proposed BSER for base load natural gas-fired c ombustion turbines. Some commenter supported partial CCS as t he BSER, others supported advanced NGCC designs as the BSER, and others supported the proposed BSER. a. Partial CCS Some commenters stated that our proposed BSER analy sis for stationary combustion turbines was inconsistent wit h our proposed BSER analysis for coal-fired units. They s tated that the EPA had determined that the use of CCS was feas ible for coal-fired generation based on current CCS projects under development at coal-fired generating stations, but did not come to the same conclusion for combustion turbines. The se commenters stated that CO 2 removal is just as technologically feasible and economically reasonable for a natural gas-fired EGU as for a coal-fired EGU. While some of these commenters want ed the EPA to reconsider CCS as the BSER for NGCC, many of these commenters were attempting to prove that if the agency did not choose CCS as the BSER for NGCC units, then the agency should not for coalfired units either. Some commenters referenced the Northeast Energy Ass ociation NGCC plant in Bellingham, MA, which operated from 1 991-2005 with*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 591 of 854 85 – 95 percent carbon capture on a 320 MW unit for use in the food and beverage industry, that was referred to in the proposal. This plant captured 330 tons of CO 2 per day from a 40 MW slip stream and was decommissioned as a result o f financial difficulties, including rising gas prices and disco ntinuation of tax credits. According to these commenters, this pl ant provided sufficient proof that CCS technology is adequately demonstrated for NGCC units. Additionally, these commenters refe rred to other NGCC plants that are planned or in development that will incorporate CCS. The plants mentioned were the Sumi tomo Chemical Plant in Japan, the Peterhead CCS project in Scotla nd, and the GE-Sargas Plant in Texas. The Sumitomo Chemical Pla nt has a base load NGCC unit with CCS operating on an 8 MW slip-s tream that captures about 150 tons of CO 2 per day for commercial use in the food and beverage industry. This carbon capture sys tem has been operating since 1994. The Peterhead CCS project in Scotland is in the planning stages. It is a collaboration betwe en Shell and SSE to provide 320 MW of electricity to its custome rs from a base load NGCC unit with 90 percent carbon capture. The CO 2 will be transported to the depleted Goldeneye reservoir in the ocean where it will be stored and continuously monitored. The GESargas Plant in Texas is a planned joint venture th at does not currently have a location selected, but is intended to be a base load NGCC unit with CCS used for EOR.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 592 of 854 These commenters also referenced reports authored b y DOE, NETL, the Clean Air Task Force (CATF), CCS Task For ce, ICF Inc., and Global CCS Institute suggesting that, because C CS technology for NGCC is included in these reports, it is adequa tely demonstrated. Some commenters referred to a DOE/NET L study that suggested that the cost of CCS for NGCC units would be more cost-effective than for coal-fired EGUs. One non-in dustry commenter emphasized that a technology does not hav e to be in use to be considered adequately demonstrated. In addition, some commenters disagreed with the EP A’s decision to treat combustion turbines differently t han coalfired units with respect to CCS on the basis that c ombustion turbines start up, shut down, and cycle load more f requently than coal-fired units. According to these commenter s, the operating characteristics of combustion turbines do fluctuate, but so do those of coal-fired units. Another commen ter said that even if NGCC operations vary more than they do for coal-fired units, it is not an impediment to using CCS because combustion turbine operators could bypass the carbon capture s ystem during startup and shutdown modes (which are typically sho rter and less intensive efforts compared to the startup or shutdo wn of a coal facility) and then employ the carbon capture system when operating normally. One commenter stated that most future base load fossil fuel-fired generation will be NGCC and that not*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 593 of 854 making CCS the BSER for NGCC would result in signif icant CO 2 emissions. Other commenters supported the EPA’s determination that CCS is not the BSER for combustion turbines. These comm enters said that CCS is not adequately demonstrated for combust ion turbines because none are currently operating, under constru ction, or in the advanced stages of development. They also noted that CCS would have to be demonstrated for the range of faci lities included in the regulated source category, which th ey alleged includes both simple cycle and NGCC units. They spe cifically noted that the Bellingham, MA demonstration facilit y was not a full-scale commercial NGCC power plant operating wi th CCS. These commenters agreed with the EPA that CCS does not match well with the operating flexibilities of NGCC and simple cycle units. They agreed with the EPA that frequent cycling restricts the efficacy of CCS on these units, a pro blem which would only get worse as more renewable energy sourc es are integrated into the grid. These commenters added th at NGCC units operate differently than coal-fired units because t he former start, stop, and cycle frequently, whereas the latt er tend to operate at relatively steady loads and do not start and stop frequently. They stated that even if technical barr iers could be overcome, the application of CCS to combustion turb ines would be more costly (compared to the application of CCS to coal-fired*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 594 of 854 units) on a dollars-per-ton basis. In addition, the se commenters said that other industries’ experience with CCS cou ld not be transferred to NGCC units due to differences in flu e gas CO 2 concentration. Some commenters stated that CAA section 111(a) requ ires the EPA to account not only for the cost of achieving e mission reductions, but also for impacts on energy requirem ents and the environment. The commenters cited to Sierra Club v. Costle, where the D.C. Circuit observed that the EPA "must exercise its discretion to choose an achievable emission level w hich represents the best balance of economic, environmen tal, and energy considerations." 564 The commenters stated that requiring CCS on combustion turbines would adversely affect t he nation’s energy needs and the environment because imposing C CS on combustion turbines would invariably delay the emis sion reductions that can be obtained from new NGCC proje cts that displace load from older, less efficient generating technologies. In addition, the commenters stated th at, because combustion turbines are projected to provide a sign ificant share of new power generation, the EPA should recognize t hat requiring CCS on these units would have a disproportionally h igher impact on electricity prices when compared to the projecte d number of

564 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir . 1981).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 595 of 854 new coal-fired projects. These commenters concluded that the EPA could not determine that CCS is the BSER for combus tion turbines without producing severe and unacceptable consequen ces for the availability of affordable electricity in the U.S. b. NGCC turbines Some commenters stated that the proposed BSER analy sis should have reflected the emission rates achieved b y the latest designs deployed at advanced, state-of-the-art NGCC installations. These commenters stated that advanced NGCC technologies are the best system for reducing CO 2 emissions with no negative environmental impacts and no negative e conomic impacts on rate payers. They stated that advanced NGCC technologies are capable of achieving emission rate s that are 8 percent lower than conventional NGCC facilities. Th ey also said that the majority of existing sources that do not d eploy these advanced technologies are currently able to meet th e standard and that the proposal failed to explain why these l ower-emitting advanced technologies that are more than adequately demonstrated

were not selected as the BSER. c. Simple cycle turbines Many commenters opposed the EPA’s proposal to set e mission standards for combustion turbines based on their fu nction rather than based on their design. These commenters stated that the EPA’s determination that NGCC technology is the BSE R for base*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 596 of 854 load natural gas-fired combustion turbines would ap ply equally to simple cycle turbines if they sell electricity i n excess of the percentage electric sales threshold. They point ed to the word "achievable" in CAA section 111(a)(1) and stat ed that applying an emission standard based on NGCC technol ogy to simple cycle units was legally indefensible because simple cycle units cannot achieve emission rates as low as NGCC units. In contrast, many other commenters agreed with the EPA’s basic a pproach and stated that NGCC technology should be the BSER for base-load functions, while simple cycle technology should be the BSER for peak-load functions. 3. Comments on Non-base Load and Multi-fuel-fired C ombustion Turbines Multiple commenters suggested that high efficiency simple cycle or fast-start NGCC technologies should be the BSER for non-base natural gas-fired load units. They explain ed that high efficiency simple cycle units and fast-start NGCC u nits are actually more efficient when serving non-base load demand than NGCC units that are designed to sell greater than strictly for base load operation. Some commenters also suggested that we should subcategorize multi-fuel-fired combustion tu rbines, but did not provide any specific technologies that shou ld be considered in the BSER analysis.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 597 of 854 4. Identification of the BSER After our evaluation of the comments and additional analysis, we identified the BSER for each subcatego ry of combustion turbine that we are finalizing: base loa d natural gas-fired units, non-base load natural gas-fired un its, and multi-fuel-fired units. a. Base load natural gas-fired units As described in the proposal, we evaluated CCS, NGC C, and high-efficiency simple cycle combustion turbines as the potential BSER for this subcategory. We selected NG CC as the BSER because it met all the BSER criteria. This sec tion describes our response to issues raised by commente rs and our rationale for maintaining that NGCC is the BSER for base load natural gas-fried combustion turbines.

(1) Partial CCS Some commenters stated that CCS could be applied eq ually to both coal-fired and natural gas-fired EGUs. To supp ort this conclusion, the commenters pointed to a retired NGC C-with-CCS demonstration project, as well as a few overseas pr ojects and projects in the early stages of development. While we have concluded that these commenters made strong argumen ts that the technical issues we raised at proposal could in man y instances be overcome, we have concluded that there is not su fficient*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 598 of 854 information at this time for us to determine that C CS is adequately demonstrated for all base load natural-g as fired combustion turbines. While the commenters make a strong case that the ex isting and planned NGCC-with-CCS projects demonstrate the feasibility of CCS for NGCC units operating at steady state con ditions, many NGCC units do not operate this way. For example, th e Bellingham, MA and Sumitomo NGCC units cited by the commenters operated at steady load conditions with a limited number of sta rts and stops, similar to the operation of coal-fired boile rs. 565 In contrast, our base load natural gas-fired combustio n turbine subcategory includes not only true base load units, but also some intermediate units that cycle more frequently, including fast-start NGCC units that sell more than 50 percen t of their potential output to the grid. Fast-start NGCC units are designed to be able to start and stop multiple times in a si ngle day and can ramp to full load in less than an hour. In cont rast, coalfired EGUs take multiple hours to start and ramp re latively slowly. These differences are important because we are not aware

565 As explained in Section V.J above, a new fossil fu el-fired steam generating EGU would, most likely, be built t o serve base load power demand exclusively and would not be expe cted to routinely start up, shut down, or ramp its capacity factor in order to follow load demand. Thus, planned start-up and shutdown events would only be expected to occur a few times during the course of a 12-operating-month compliance period.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 599 of 854 of any pilot-scale CCS projects that have demonstra ted how fast and frequent starts, stops, and cycling will impact the efficiency and reliability of CCS. Furthermore, for those periods in which a NGCC unit is operating infrequen tly, the CCS system might not have sufficient time to start up. During these periods, no CO 2 control would occur. Thus, if the NGCC unit is intended to operate for relatively short intervals for at least a portion of the year, the owner or operator could have to oversize the CCS to increase control during periods of steadystate operation to make up for those periods when n o control is achieved by the CCS, leading to increased costs and energy penalties. While we are optimistic that these hurdl es are surmountable, it is simply premature at this point to make a finding that CCS is technically feasible for the un iverse of combustion turbines that are covered by this rule. Notably, the Department of Energy has not yet funde d a CCS demonstration project for a NGCC unit, and no NGCC- with-CCS demonstration projects are currently operational or being constructed in the U.S. In contrast, multiple CCS d emonstration projects for coal-fired units are in various stages of development throughout the U.S., and a full-capture system is in operation at the Boundary Dam facility in Canada. S ee Sections

V.E and D above.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 600 of 854 One commenter suggested that not having CCS as the BSER for combustion turbines would ultimately halt the devel opment of CCS in the U.S. We disagree. A number of coal-fired pow er plants are currently being built with CSS, while some existing plants are considering CCS retrofits. Moreover, the NSPS sets the minimum level of control for new sources. We expect that st ate air agencies and other air permitting authorities will evaluate CCS when permitting new NGCC power plants, taking into consideration case-specific parameters, like operating characteri stics, to determine whether CCS could be BACT or LAER in spec ific instances. While the NGCC-with-CCS units that curre ntly are in the planning stages do not provide us with enough a ssurance to determine that CCS is adequately demonstrated for c ombustion turbines, it is our expectation that these units an d others to come will provide additional information for both p ermitting reviews and the next NSPS review in eight years. (2) NGCC turbines Regarding the advanced NGCC technologies advocated by several commenters, the EPA has concluded that the term “advanced” simply refers to incremental improvement s to traditional NGCC designs, not a new and unique tech nology. These incremental improvements include higher firing temp eratures in the turbine engine, increasing the number of steam pressures, and adding a reheat cycle to the steam cycle. The e mission rates*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 601 of 854 achieved by these so-called “advanced” technologies were included within the data set of newer NGCC designs that we used to establish the final emission standards. In addit ion, our review of the operating data for NGCC power blocks installed since 2000 indicates that a unit’s mode of operatio n in response to system demand (e.g., capacity factor) affects ef ficiencies achieved to the extent that we cannot evaluate the impact of particular subcomponents used within the power bloc k. As a result, a conventional NGCC power block located in a region of the country where system demand requires the power block to run continuously at a steady high load can achieve high er efficiencies than an “advanced” NGCC power block lo cated in a region where system demand requires the power block to cycle on and off to match system demand. For this reason, ou r data set included a large population of technologies and loa d conditions to ensure that new NGCC power blocks can achieve th e final emission standards in all regions of the country. As we explained in the proposal, NGCC technology me ets all of the BSER criteria. For base load functions, NGCC units are technically feasible, cost-effective (indeed, less expensive than simple cycle combustion turbines), and have no adverse energy or environmental impacts. Moreover, NGCC uni ts reduce emissions because they have a lower CO 2 emission rate than simple cycle units. Finally, selecting NGCC as the BSER wi ll promote*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 602 of 854 the development of new technology, such as the incr emental improvements advocated by the commenters, which wil l further reduce emissions in the future. Some commenters suggested that the costs and effici ency impacts of startup and shutdown events are higher f or NGCC units than for simple cycle units. Consequently, we refin ed the LCOE costing approach used at proposal by adding these a dditional costs and efficiency impacts to our cost comparison . Even accounting for these new costs and impacts, we foun d that NGCC technology results in a lower cost of electricity t han simple cycle technology when a unit’s electric sales excee d approximately one-third of its potential electric output , adding heat recovery and converting to a combined cycle is both cost effective (i.e., results in a lower cost of electri city) and results in a lower emission rate. The proposed stan dards of. The final percentage electric sales criterion for the b ase load natural gas-fired combustion turbine subcategory is based on the sliding scale. This means that the dividing line be tween the base load subcategory and the non-base load subcate gory will change depending on a unit’s nameplate design effic iency. For a conventional simple cycle turbine, the base load su bcategory will begin at around 33 percent electric sales, whi le for a newer fast-start NGCC turbine, the base load subcat egory will begin at approximately 50 percent electric sales. A nywhere*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 603 of 854 within this range, our cost calculations have shown that NGCC technology is more cost-effective than simple cycle technology. Therefore, we are finalizing our determination that modern, efficient NGCC technology is the BSER for base load natural-gas fired combustion turbines. (3) Simple cycle turbines Many commenters mistakenly thought that the EPA pro posed to require some simple cycle combustion turbines to me et an emission standard of 1,000 lb CO 2 /MWh-g, a level that they assert is unachievable. On the contrary, the EPA is not fi nding that NGCC technology and a corresponding emission standa rd of 1,000

lb CO 2 /MWh-g is the BSER for simple cycle turbines. Inste ad, the EPA is finding that NGCC technology is the BSER for base load turbine applications. This means that if an owner o r operator wants to sell more electricity to the grid than the amount derived from a unit’s nameplate design efficiency c alculated as a percentage of potential electric output, then the owner or operator should install a NGCC unit. If the owner o r operator elects to install a simple cycle turbine instead, t hen the practical effect of our final standards will be to limit the electric sales of that unit so that it serves prima rily peak demand, not to subject it to an unachievable emissi on standard.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 604 of 854 b. Non-base load natural gas-fired load units To identify the BSER for non-base load natural gas- fired units, we evaluated a range of technologies, includ ing partial CCS, high-efficiency NGCC technology designed for b ase load applications, fast-start NGCC, high-efficiency simp le cycle units (i.e., aeroderivative turbines), and clean fu els. For each of these technologies, we considered technical feas ibility, costs, energy and non-air quality impacts, potentia l for emission reductions, and ability to promote technol ogy. While CCS would result in emission reductions and p romote the development of new technology, we concluded tha t CCS does not meet the BSER criteria because the low capacity factors and irregular operating patterns (e.g., frequent starti ng and stopping and operating at part load) of non-base lo ad units make the technical challenges associated with CCS even g reater than those associated with base load units. In addition, because the CCS system would remain idle for much of the time w hile these units are not running, the cost-effectiveness of CC S for these units would be much higher than for base load units

. We have also concluded that the high-efficiency NGC C units designed for base load applications do not meet any of the BSER criteria for non-base load units. First, non-base l oad units need to be able to start and stop quickly, and NGCC units designed for base load applications require relativ ely long*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 605 of 854 startup and shutdown periods. Therefore, convention al NGCC designs are not technically feasible for the non-ba se load subcategory. Also, non-base load units operate less than 10 percent of the time on average. As a result, conven tional NGCC units designed for base load applications, which ha ve relatively high capital costs, will not be cost-effective if o perated as non-base load units. In addition, it is not clear t hat a conventional NGCC unit will lead to emission reduct ions if use for non-base load applications. As some commenters noted, conventional NGCC units have relatively high startu p and shutdown emissions and poor part-load efficiency, s o emissions may actually be higher compared with simple cycle t echnologies that have lower overall design efficiencies but bet ter cycling efficiencies. Finally, requiring conventional NGCC units as the BSER for non-base load combustion turbines would no t promote technology because these units would not be fulfill ing their intended role. In fact, it could hamper the develop ment of technologies with lower design efficiencies that ar e specifically designed to operate efficiently as non -base load units (i.e., high-efficiency simple cycle and fast- start NGCC units). For all these reasons, we have concluded th at conventional NGCC units designed for base load appl ications are not the BSER for non-base load natural gas-fired un its.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 606 of 854 Compared to conventional NGCC technology, fast-star t NGCC units have lower design efficiencies, but are able to start and ramp to full load more quickly. Therefore, it is po ssible that requiring fast-start NGCC as the BSER for non-base load units would result in emission reductions and further pro mote the development of fast-start NGCC technology, which is relatively new and advanced. However, because the majority of non-base load combustion turbines operate less than 10 percent of the time, it would be cost-prohibitive to require fast-start NGC C, which have relatively high capital costs compared to simple cy cle turbines, as the BSER for all non-base load applications. Als o, as we explained above in Section IX.B.2, we do not have s ufficient emissions data for fast-start NGCC units operating over the full range of non-base load conditions (e.g., peaking, c ycling, etc.), so we would not be able to establish a reaso nable emission standard. High-efficiency simple cycle turbines are primarily used for peaking applications. High-efficiency simple cy cle turbines often employ aeroderivative designs because they ar e more efficient at a given size and are able to startup a nd ramp to full load more quickly than industrial frame design s. Requiring high-efficiency simple cycle turbines as the BSER c ould result in some emission reductions compared with conventio nal simple cycle turbines. It would also promote technology de velopment by*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 607 of 854 incentivizing manufacturers to increase the efficie ncy of their simple cycle turbine models. However, aeroderivativ e designs have higher initial costs that must be weighed agai nst the specific peak-load profiles anticipated for a parti cular new non-base load unit. Many utility companies have ele cted to install the heavier industrial frame turbines becau se the ramping capabilities of aeroderivative turbines are not required for their system demand profiles (i.e., the speed a nd durations of daily changes in electricity demand), and the fu el savings do not justify the higher initial costs. We currently do not have precise enough costing information to compare the c osteffectiveness of aeroderivative turbines and indust rial frame turbines for all non-base load applications. Determ ining costeffectiveness is further complicated because the ef ficiencies of the available aeroderivative and industrial frame t echnologies significantly overlap. For example, the efficiencie s of aeroderivative turbines range from 32 to 39 percent , while the efficiencies of industrial frame turbines range fro m 30 to 36 percent. Based on these cost uncertainties, we cann ot conclude that high-efficiency simple cycle turbines are the BSER for natural gas-fired non-base load applications at thi s time. The final option that we considered for the BSER wa s clean fuels, specifically natural gas with a small allowa nce for distillate oil. The use of clean fuels is technical ly feasible*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 608 of 854 for non-base load units. Based on available EIA dat a, 566 natural gas comprises more than 96 percent of total heat in put for simple cycle combustion turbines. In addition, natu ral gas is frequently the lowest cost fossil fuel used in comb ustion turbines, so it is cost-effective. Clean fuels will also result in some emission reductions by limiting the use of fuels with higher carbon content, such as residual oil. Finall y, the use of clean fuels will not have any significant energy or non-air impacts. Based on these factors, the EPA has determ ined that the BSER for non-base load natural gas-fired units is t he use of clean fuels, specifically natural gas with a small allowance for distillate oil. Natural gas has approximately thirt y percent lower CO 2 emissions per million Btu than other fossil fuels commonly used by utility sector non-base load units

. c. Multi-fuel-fired units To identify the BSER for multi-fuel-fired units, we again evaluated CCS, NGCC technology, high-efficiency sim ple cycle units (i.e., aeroderivative turbines), and clean fu els. For each of these technologies we considered technical feasi bility, costs, energy and non-air quality impacts, emission reductions, and technology promotion. For many of the same reas ons we provided above in our discussion of the BSER for no n-base load

566 http://www.eia.gov/electricity/data/eia923/.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 609 of 854 natural gas-fired combustion turbines, only clean f uels meets the BSER criteria for multi-fuel-fired units. While CCS would result in emission reductions and t he promotion of technology, we concluded that CCS does not meet the BSER criteria because multi-fuel-fired units tend t o start, stop, and operate at part load frequently. Also, th ere are impurities and contaminants in some alternate fuels which make the technical challenges of applying CCS to multi-f uel-fired units greater than for natural gas-fired units. In regards to NGCC technology, we have concluded th at it is technically feasible, would result in emission redu ctions, is cost-effective, and would promote the development o f technology. However, a BSER determination based on the use of N GCC technology could pose challenges for facilities ope rating in remote locations and certain industrial facilities. In remote locations, the construction of a NGCC facility is o ften not practical because it requires larger capital invest ments and significant staffing for construction and operation . In contrast, simple cycle turbines are cheaper and can be operated with minimal staffing. Also, many industrial facili ties do not have the space available to build a HRSG and the as sociated cooling tower. Therefore, requiring NGCC as the BSE R could have unforeseen energy impacts at these types of facilit ies. Moreover, these same kinds of facilities also burn by-product*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 610 of 854 fuels. Faced with a decision to install an NGCC uni t, these facilities might seek alternative energy options, w hich could lead to increased flaring or venting of by-product fuels because they are no longer being burned onsite for energy r ecovery. Therefore, in light of these potential energy and n on-air quality impacts, we have concluded that NGCC techno logy is not the BSER for multi-fuel-fired combustion turbines. Similarly, while high-efficiency simply cycle turbi nes would result in emission reductions and promote the advancement of this technology, we are not confident that high- efficiency simple cycle units are technically feasible or cost -effective for this subcategory. Aeroderivative turbines are n ot as flexible with regards to what fuels that can be bur ned. Because by-product fuels vary in composition, it is not cle ar that all by-products fuels could be burned in a high-efficie ncy simple cycle turbine. In addition, even if a by-product fu el could be burned in an aeroderivative turbine, we do not have information on the potential for increased maintenance costs, w e so cannot determine whether using high-efficiency simple cycl e turbines would be cost-effective. The final option that we considered for the BSER wa s clean fuels. The use of clean fuels is technically feasib le and costeffective. The use of clean fuels also provides an environmentally beneficial alternative to the flari ng or venting*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 611 of 854 of by-product fuels and limits the use of dirtier f uels with higher CO 2 emission rates, such as residual oils. Clean fuels also promote technology development by allowing man ufacturers to develop new combustion turbine designs that are cap able of burning by-product fuels that currently cannot be b urned in combustion turbines. Finally, the use of clean fuel s does not have any significant energy or non-air quality impa cts. Based on these factors, the EPA has determined that the BSER for multifuel-fired combustion turbines is the use of clean fuels.

D . Achievability of the Final Standards We are finalizing emission standards for three subcategories of combustion turbines. Specifically, units that sell electricity in excess of a threshold based on their design efficiency and that burn more than 90 percent natur al gas (i.e., base load natural gas-fired units) will be subject to an outputbased standard. The output-based standard is based on the performance for natural gas-fired stationary combustion turbine s were in the form of a gross-output-based emission l imit expressed in units of mass of CO 2 per unit of gross energy output, specifically, in lb CO 2 /MWh-gross. The subcategories for which the EPA proposed separate standards of perfor mance were (1) large natural gas-fired stationary combustion t urbines with a of existing NGCC units and takes into account a r ange of operating conditions, future degradation, etc. Unit s not meeting*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 612 of 854 either the percentage electric sales or natural gas -use criteria (i.e., non-base load natural gas-fired and multi-fu el units, respectively) will be subject to an input-based sta ndard based on the use of clean fuels. This section summarizes what emission standards we proposed and related issues we solicit ed comment on, describes the comments we received regarding th e proposed emission standards and our responses to those comme nts, and our rationale for the final emission standards. 1. Proposed Standards For large newly constructed, modified, and reconstr ucted stationary combustion turbines ( base load rating greater than 850 MMBtu/h 567 and (2)), we proposed an emission standard of 1,000 lb CO 2 /MWh-g. For small natural gas-fired stationary combustion turbines with a ( base load rating less than or equal to 850 MMBtu/h. The EPA solicited comment on a broa d range of issues related to the final standard. For new, modi fied, and reconstructed units we proposed a limit of 1,000 lb CO 2 /MWh-gross for large units (base load heat input rating greate r than of 850 MMBtu/h ) and or less), we proposed an emission standard o f 1,100 lb CO 2 /MWh- gross for small units (base load heat input

567 This subcategorization of stationary combustion tu rbines is consistent with the subcategories used in the combu stion turbine (subpart KKKK) criteria pollutant NSPS. The size li mit of 850 MMBtu/h corresponds to approximately 100 MWe. Based on the largest aeroderivative turbine design available whe n subpart KKKK originally promulgated*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 613 of 854 rating of 850 MMBtu/h or less). Weg. We also solicited comment on a range of 950 – 1,100 lb CO 2 /MWh -g for large stationary combustion turbines and an emission standarda range of 1,000 – 1,200 lb CO 2 /MWh -g for small stationary combustion turbines. We also In addition, we solicited comment on eliminating the size subcategory, increasing the size distinction between large and small stationary combustion turbines to 900 MMBtu/h to account for larger aeroderivative designs , to ; increasing the size

distinction to 1,000 MMBtu/h to account for future incremental increases in base load ratings , or on; increasing the size distinction to between 1,300 to 1,800 MMBtu/h . In addition, we solicited comment on establishing a variable capaci ty factor threshold that would allow more efficient, lower em itting turbines to run and be permitted for longer periods of operation (e.g., a higher capacity factor for the most effici ent turbines being progressively lowered for lower efficiency tu rbines).; and eliminating the size subcategories altogether. To a ccount for potential reduced efficiencies when units are not o perating at base load, we also solicited comment on whether a s eparate, less stringent standard should be established for non-ba se load combustion turbines. With respect to the size subcategory, some commente rs and others agreed with the 850 MMBtu/h break point betw een large and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 614 of 854 small units, some suggested increasing it to 1,500 MMBtu/h, and others suggested eliminating the size based subcate gorization. Some commenters stated that the current 850 MMBtu/h size distinction is inappropriate for CO 2 because it was originally determined based on NO X performance and not significant for CO 2 emission rates. These commenters stated that the 85 0 MMBtu/h cut-point, when compared to the existing fleet, doe s not result in a logical cut-point with a clear demarcation of higher emitting versus lower emitting technology on either side of this value, but rather divides the units at an arbitrary size classification. These commenters suggested 1,500 MM Btu/h since there is a clear cut-point in the existing fleet of gas turbines between the heat input range of 1,300 MMBtu/h and 1 ,800 MMBtu/h, with more efficient and lower CO 2 emitting technology above and below 1,500 MMBtu/h. In contrast, other commenters said that differentia tion of small and large gas turbines cannot be justified be cause many of the same technologies that reduce the emission rate s of larger units could be incorporated into smaller units. Com menters also said that separate standards for small and large tu rbines undermine the incentive for technology innovation, a key purpose of the NSPS program, and that relaxing standards fo r smaller units will discourage investment in more efficient technologies. These commenters recommended that the limit for bot h large and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 615 of 854 small units be no higher than 1,000 lb CO 2 /MWh. Finally, some commenters suggested that the EPA should regulate m ultiple small units built together as a single large unit if the combined heat input capacity of all gas turbines at the facility exceeds 850 MMBtu/h. Numerous commenters from the power sector, air perm itting authorities, and environmental groups acknowledged that accelerating renewable portfolio standards in certa in states coupled with NERC reliability requirements can affe ct the performance of combined cycle natural gas EGUs as t hey are increasingly cycled and operated at lower capacity factors to complement hourly variations in intermittent renewa ble generation (e.g., solar and wind). However, comment ers had a wide range of opinions on the extent to which inter mittent renewables should be used to justify increasing the national emissions standard above the emission rate that can be achieved by well-operated and maintained intermediate and ba se-loaded combined cycle plants. Commenters from the power sector generally supporte d increasing the standard for each subcategory 2. Comments As described previously, we are not finalizing the sizebased subcategories that we proposed and instead ar e finalizing emission standards for sales- and fuel-based subcat egories. Specifically, we are finalizing emission standards for three*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 616 of 854 subcategories of stationary combustion turbines: ba se load natural-gas fired units, non-base load natural gas- fired units and multi-fuel-fired units. The relevant comments c oncerning the emission standards for the first two subcategories are discussed below. Any comments we received supporting tiered e mission standards are included in the discussion of non-bas e load natural gas-fired units. We did not receive comment s on an appropriate emission standard for multi-fuel-fired units. a. Emission standards for base load natural gas-fir ed units Many commenters stated that the proposed emission s tandards did not properly take into account the losses in ef ficiency that occur due to long-term degradation over multiple de cades, operation at non-base load conditions (load cycling , frequent startups and shutdowns, and part-load operations), site-specific factors such as ambient conditions and cooling tech nology, and secondary fuel use (e.g., distillate oil). These co mmenters stated that the EPA should conduct a more comprehen sive analysis that addresses worst-case conditions for each of th ese factors. They also stated that all of the units included in the analysis supporting the proposal were relatively new and the refore have experienced limited degradation. The commenters sta ted that, while some degradation in efficiency can be recover ed during periodic maintenance outages, it is not always poss ible or feasible to repair a degraded component immediately because*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 617 of 854 repairs often involve extended outages that must be scheduled well in advance. They stated that a new unit that i nitially could meet the standard at base load conditions can experience increasing heat rates with age even when adhering t o the manufacturer's recommended maintenance program. Some commenters stated that the proposed standards were derived by looking at emissions data from years wit h historically low natural gas prices. They surmised that the NGCC units were taking advantage of these prices by runn ing at historically high capacity factors and concluded th at the efficiencies and CO 2 emission rates underlying the proposed standards were not representative of periods with h igher natural gas prices. Other commenters said that many NGCC un its are increasingly required to cycle and operate at lower capacities (compared to the proposal's baseline) to accommodat e hourly variations in intermittent renewable generation. Th ey anticipated that this type of generation will incre ase, requiring NGCC units to start, stop, and operate at part load more frequently than in the past, increasing CO 2 emissions. Some commenters indicated that, during startup, com bustion turbines must be operated at low load for extended periods to gradually warm up the HRSG to minimize thermal stre sses on pressure vessels and boiler tubes. During these sta rtup periods, significant CO 2 emissions occur, but steam production is not*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 618 of 854 sufficient for the steam turbine generator to produ ce electricity. They also stated that a similar situat ion occurs during shutdown when the steam cycle does not gener ate electricity, but the combustion turbine is still co mbusting fuel as it proceeds through the shutdown process. These commenters recommended that the EPA could address these issues by creating a subcategory for NGCC units that cycle and operate at intermediate load. Many commenters said that site-specific factors can often preclude operators from achieving design efficienci es based on ISO conditions. These factors include high elevatio ns, high ambient temperatures, and cooling system constraint s. They stated that local water temperatures can impact con denser operating pressure and heat rates. They also said t hat areas with limited water resources could require systems that rely on air-cooled condensers, which cannot achieve thermal efficiencies comparable to water-cooled plants. These commenters stated that the final rule should include provisions for addres sing sitespecific constraints that preclude individual affec ted EGUs from achieving the emissions rates achieved on average b y other

sources. Some commenters stated that the proposed standards for modified and reconstructed combustion turbines woul d foreclose future opportunities for operators to undertake pro jects to*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 619 of 854 restore the performance of both degraded units subj ect to the NSPS and existing, pre-NSPS units. They said that i t is not possible to bring older combustion turbines (built prior to the year 2000) up to the efficiency levels of modern un its because many newer technological options that deploy higher temperatures are not available for pre-2000 combustion turbines. Commenters from the power sector generally supporte d increasing the standards to 1,100 lb CO 2 /MWh- gross for large unitsg and 1,200 lb CO 2 /MWh- grossg for the newly constructed large and small units andturbines, respectively. They also

advocated finalizing standards for modified and reconstructe d standards that are 10 percent higher than the final standards

for newly constructed combustion turbinesnew sources because combustion turbines constructed prior to 2000 were not included in the EPA's BSER analysis for new sources. . Conversely, some commenters stated that the propose d standards for combustion turbines do not reflect th e emission rates that are achievable by modern, efficient NGCC power blocks , and these commenters do not believe the proposed numerical standards meet the CAA section 111 requir ements for

BSER. Some. These commenters stated that the appropriate limitationstandard , consistent with Congressional objectives under CAA section 111, isshould be 800 lb CO 2 /MWh- grossg based on the performance of the lowest emitters in the CAMD database.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 620 of 854

Some commenters stated that a limitationstandard of 850 lb

CO 2 /MWh- gross reflectedg reflects BSER for high-capacity factor units because half of the combined cycle plantsNGCC units in the CAMD database are achieving this level of emissions . One commenter from the power sector who operates combined cycleNGCC power plants stated that the final standard for new large combustion turbines should be 925 lb CO 2 /MWh- gross.g. Another also commenter supported an emission standard of 92 5 lb CO 2 /MWhg, which is consistent with recent BACT determinati ons in the

state of New York. Several other commenters stated that a

reasonable standard for new large combustion turbines

wouldshould be 950 lb CO 2 /MWh- gross, and several commenters statedg and that the final standard for new small combustion turbines should be 10001,000 lb CO 2 /MWh- grossg . Numerous commenters stated that the final standardstandards for new sources should not exceed 1,000 lb CO 2 /MWh- grossg for either large or small combustion turbines. Other commenter s stated that since, because the standards were developed based on emission rates that are being achieved by the majority of ex isting units, the final standards should be the same for new, mod ified, and reconstructed units. These commenters stated that since the standards were developed based on emission rates th at are being achieved by the majority of existing units, the fin al standards should be the same for new, modified, and reconstru cted units.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 621 of 854 Numerous commenters supported tiered subcategories b. Emission

standards for peaking, load-following/intermediate, and non- base

load natural gas-fired units . Commenters noted that the EPA’s proposals excluded and multi-fuel-fired units Many commenters stated that operate the EPA cannot finalize “no emission standard” for non-base load units, whi ch the EPA solicited comment on in peaking mode and the broad applicability approach. They argued that this approach was not consistent with the definition of “standard of performance” in CAA section 111(a)(1), which requires there is no basis in law or policy to exempt units from regulation simply because they op erate less frequently, and hence less efficiently. Commenters said the EPA be an “emission limitation” that reflects a “system of emission reduction.” Some commenters recommended that non-ba se load units

should cover all sources that supply (or are designedbe su bject

to supply) any amount of electricity to the grid, and should distinguish subcategories based on actual operation . Several commenters supported tiered work practice standards based on capacity factor. They proposed 825 lb CO 2 /MWh-gross for base load units (those, such as operating over 4,000 hours annually), 875

lb CO 2 /MWh-gross for intermediate and load-following unit s (those operating between 1,200 and 4,000 hours annually), and 1,100 lb

CO 2 /MWh-gross for peaking units (those operating less than 1,200 hours per year). One of the most common comments re ceived was*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 622 of 854 that peaking units should be either included in a s ubcategory or completely exempted due to the highly variable capa city factors and duty cycles imposed by system operators on thes e versatile generators. Numeroussafely with good air pollution control practices, including CO 2 monitoring and reporting requirements.

Other commenters pointed to recent BACTPSD permits that include tiered emission limits for CO 2 that indicate tiered limits are appropriate for the different roles served by combustion turbines citing. They cited BACT limits from 1,328 to 1,450 lb

CO 2 /MWh- grossg for peaking units. One commenter supported tiered limits consistent with recent BACT determinations i n the

Statestate of New York : a combined cycle limit of 925 lb CO 2 /MWhgross and a , which include limits for simple cycle limit combustion turbines of 1,450 lb CO 2 /MWh- grossg . An air quality regulator from a state with rapidly increasing rene wable generation supported a limit of 825 lb CO 2 /MWh- grossg for all base load NGCC units; 1,000 lb CO 2 /MWh- gross for g for large intermediate load NGCC units; 1,100 lb CO 2 /MWh-g for small intermediately loaded, large NGCC units; 1,100 lb CO 2 /MWh-gross for intermediately loaded, small load NGCC units ; and this. This

commenter also recommended that the EPA set a numerical limit specifically for peaking units after the completion of a peakerpeaking unit -specific BSER analysis.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 623 of 854 Several commenters supported tiered standards based on capacity factor. They proposed 825 lb CO 2 /MWh-g for base load units (those operating over 4,000 hours annually), 875 lb

CO 2 /MWh-g for intermediate and load-following units (t hose operating between 1,200 and 4,000 hours annually), and 1,100 lb

CO 2 /MWh-g for peaking units (those operating less than 1,200 hours per year). 3. Final Standards a. Newly constructed base load natural gas-fired un its In evaluating the achievability of the base load na tural gas-fired emission standard, we focused on three ty pes of data. Specifically, we looked at existing NGCC emission r ates, recent PSD permit limits for CO 2 emissions, and NGCC design efficiency data and specifications. Based on this analysis, we have concluded that an emission rate of 1,000 lb CO 2 /MWh-g is appropriate for all base load natural gas-fired com bustion turbines, regardless of size. Other commenters opposed the tiered approach. Commenters suggested that separate standards for different ope rating conditions would be complicated to implement and en force, provide few benefits, and could have the unintended consequence of encouraging less efficient technologies and less efficient operation. Commenters added that annual capacity fa ctors would likely vary significantly from year to year, and po ssibly from*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 624 of 854 month to month as the 12 operating month average is recalculated every operating month. The commenters stated that t his realworld variability and uncertainty significantly dim inishes the value of creating tiered standards for peaking and loadfollowing units because individuals responsible for long-range decisions related to reliability may react to a sys tem of tiered standards by purchasing additional generating asset s to ensure system demand can be satisfied while operating indi vidual units below tier-specific thresholds. After further evaluation, the EPA has concluded aga inst subcategorizing the combustion turbine standard bas ed on size for several reasons. While some commenters suggeste d that the division between large and small should be increase d to 1,500 MMBtu/h, other commenters said subcategorizing base d on size would distort the market and provide a regulatory i ncentive to install less efficient, smaller combined cycle faci lities, resulting in increased GHG emissions. The EPA revie wed data on the size of available combined cycle facilities (wi thout duct burners) listed in Gas Turbine World. Combined cycl e turbines are not currently offered in the following output s izes: between 600 to 800 MMBtu/h, 1,000 to 1,200 MMBtu/h, and 1,3 00 to 1,800 MMBtu/h based on the heat input to the combustion t urbine engine. However, a review of heat input data by the EPA for combined cycle facilities submitted to the EPA Clea n Air Markets*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 625 of 854 Division show that multiple combined cycle faciliti es have been built in the past with heat input capacities with t he capacities listed above. Therefore, the EPA has concluded that the regulated community uses various sizes of combined cycle facilities and that no clear cut point distinguishe s small and large combined cycle facilities. Subcategorizing by size could unduly influence the selection of technology and de velopment of future turbine offerings. Further, the average emis sions rate of combined cycle facilities of less than 850 MMBtu/h (the proposed cut point) is lower than the average emissions rate of combined cycle facilities with heat input ratings of 850 MMB tu/h up to 1,500 MMBtu/h. Finally, the EPA has concluded that, while certain smaller combined cycle designs are less eff icient than larger combined cycle designs, this is primarily re lated to design choices of the heat recovery steam generator , and is not an inherent limitation in the technical ability of small combined cycle technologies to have comparable effi ciencies to large combined cycle facilities.

Since the standards were proposed, the EPA has expanded the NGCC emissionsemission rate analysis that supported the proposed emission standards to include emission s information

for combined cycle facilitiesNGCC units that commenced operation in 2011, 2012, and 2013 , and updated the emissions data to include emissions through 2014. Based on analysis of these data*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 626 of 854 and the comments submitted on the proposed standard , the EPA has concluded that an emission standard of 1,000 lb CO 2 /MWh-gross is achievable for all affected combustion turbines. Th erefore, the EPA is finalizing an emission standard of 1,000 lb/ MWh-gross for all combustion turbines without any size based subc ategories. Emissions data from combined cycle facilities with heat input ratings of less than 850 MMBtu/h have demonstrated that this level is achievable for smaller combined facilities . The sixteen NGCC facilitiesIn our analysis, we evaluated using the Clean Air Markets data have heat input rates of less than or equal to 850 MMBtu/h and an average 12-month maximum 346 NGCC un its with online dates ranging from 2000 to 2013. The analysi s included emissions data from 2007 to 2014 as submitted to th e EPA’s CAMD. The average maximum 12-operating-month CO 2 emission rate for all NGCC units was 897 lb CO2/MWh-g, with individual un it maximums ranging from 751 to 1,334 lb CO 2 /MWh-g. Consistent with our proposed size-based subcategori es, we also reviewed the emissions data for small and larg e NGCC units separately. For small units, we evaluated emissions data from 17 NGCC units with heat input ratings of 850 MMBtu/h o r less. These units had an average maximum 12-operating-month CO 2 emission rate

of 952953 lb/MWh- gross. Threeg. Individual unit maximum emission rates ranged from 898 to 1,175 lb CO 2 /MWh-g. Two of the facilities evaluated using the Clean Air Markets da taunits had a*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 627 of 854 maximum 12-operating month rolling average emissions rate equal to or greater than 1,000 lb CO 2 /MWh- gross. Oneg. 568 However, one of those facilities hadthe units with a maximum 12-operatingmonth rolling average emissionsemission rate equal to or greater than 1,100 lb CO 2 /MWh-gross.above 1,000 lb CO 2 /MWh was only selling approximately 20 percent of its potential e lectric output (significantly below the design-specific per centage electric sales threshold) when the emission rate oc curred. If this unit were a new unit, the applicable emission standard would be the heat input-based clean fuels standard, and the unit would not be out of compliance. Therefore, 16 of th e 17 existing small NGCC units have demonstrated that an emission rate of 1,000 lb CO 2 /MWh-g is achievable. In addition, the five facilities that six newest units, which commenced construction between 2007 and 2012 , all have maximum 12- operating- month emission rates of less than 950 lb CO 2 /MWh- gross. For larger units, twenty-five of the 314 combined cycle facili ties with heat input ratings greater than 850 MMBtu/h had max imum 12-month average emission rates greater than 1,000 lb CO 2 /MWh. The analysis inherently includes multiple years of data and did not filter out periods of startup, shutdown, operation at

568 For emission standards of 1,000 lb CO2/MWh-g and a bove, the emission standard uses three significant figures. S ee Section X.D.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 628 of 854 intermediate load, or cycling when determining the maximum 12- operating month emission rate. Theg. While these un its might not be old enough to have experienced degredation, thei r maximum emission rates demonstrate that the final standard of 1,000 lb

CO 2 /MWh-g includes a sufficientsignificant compliance margin to

account for any performancefuture degredation in the operation of these facilities. . In addition, multiple technologies that can increas e the performance of new combined cycle facilities are cu rrently available. First, vendors continue to improve the s ingle cycle efficiency of combustion turbines. The use of more efficient combustion turbine engines improves the overall eff iciency of combined cycle facilities. In addition, existing sm aller combined cycle facilities were likely designed usin g single or dual pressure heat recovery steam generators withou t a reheat cycle. New designs could incorporate three pressure steam generators with a reheat cycle to improve the overa ll efficiency of the combined cycle facility. Additional technolo gies to reduce emission rates for new combustion turbines i nclude CHP and integrated non-emitting technologies. The EPA reviewed the GHG limitations in recently is sued constructionFor large units, the average maximum 12 -operatingmonth emission rate was 895 lb CO 2 /MWh-g, with individual unit maximum emission rates ranging from 751 to 1,334 lb CO 2 /MWh-g.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 629 of 854 Twenty-three of the 328 large NGCC units had maximu m 12- operating-month emission rates greater than 1,000 l b CO 2 /MWh. While we do not have precise design efficiency info rmation for each of these units, and thus cannot calculate the precise percentage electric sales threshold to which each u nit would be subject, it appears that all of the emission rates in excess of 1,000 lb CO 2 /MWh-g occurred during periods when electric sales were low and would be below the threshold. Thus, if these units were new units, they would only have to comply with the heat input-based clean fuels standard. Therefore, essent ially all existing NGCC units would have been in compliance w ith the final emission standard. We note also that there are 51 new NGCC units that have started operation since 2010, and the ave rage maximum 12-operating-month emission rate for these units is 833 lb

CO 2 /MWh-g. Therefore, the final emission standard incl udes a very significant compliance margin to account for any po tential future degredation of large units. To evaluate degredation further, the EPA reviewed t he emission rate information for the 55 oldest NGCC un its in our data set (i.e., units that came online in 2000 and 2001). According to the commenters, we should expect to se e degredation when reviewing the annual emissions data for these turbines because they are 14 to 15 years old. However, we di d not see any sign of degredation. The CO 2 rates for these turbines have little*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 630 of 854 standard deviation between 2007 and 2014. In additi on, there were many instances where the CO 2 emission rate of a unit actually decreased with age. This indicates that th e efficiency of the unit is increasing, possibly as a result of good operating and maintenance procedures or upgrades to equipment that improved efficiency beyond the original design . Based on these findings, we have concluded that our analysis adequately accounts for potential degredation. We also evaluated the impact of elevation, ambient temperature, cooling type, and operating conditions (startups, shutdowns, and average run time per start) because commenters indicated that these could affect a unit's ability to achieve the standard. We saw little correlation between ele vation or ambient temperature and emission rate. In addition, any correlation was relatively small and would have an insignificant impact on the ability of a unit to achieve the fina l standard. We identified 32 large NGCC units with dry cooling towers. The average maximum 12-operating-month emission rate fo r this group of units was 875 lb CO 2 /MWh. This rate was actually lower than the average rate for the large NGCC group as a whol e. Based on these findings, we have concluded that the final em ission standard will not limit the use of dry cooling tech nologies. Finally, the EPA evaluated the impact of run time p er start, average duty cycle, and number of starts on emissio n rates.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 631 of 854 While these factors do influence emission rates, th e non-base load natural gas-fired subcategory inherently addre sses efficiency issues related to operating conditions. In addition to evaluating existing NGCC emissions d ata, the EPA reviewed the CO 2 emission limits included in PSD preconstruction permits for NGCC facilities.issued since January 1, 2011. We evaluated all permit limits over an ann ual period.

In total , we identified 31 major source PSD permits were identified with 39 discrete limits on GHGCO 2 emissions. Eight of the limits were expressed as lbsin terms of lb /h or tons per

year and were, so we did not includedinclude them in the analysis. In addition, Oneone CHP unit that generates electricity and supplies steam to a chemical plant was in the

data set with. This facility had a permit limit of 1,362 lb

CO 2 /MWh based only on the gross electrical portion of output and

does not account for the useful thermal output. Therefore, it was alsowe did not includedinclude it in thisthe analysis . Two of the either. Finally, we excluded two permits that did not clearly specify if the output - based standard was on a gross or net basis and were therefore also excluded. The .

The remaining 28 permit standardslimits were expressed on ain lb CO 2 /MWh or a heat rate basis that could be converted t o a lb CO 2 /MWh basis . Eight permit limits were based on net output , ranging from 774-936 lb CO 2 /MWh- netn . The lowest emission limit*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 632 of 854 was for a hybrid power plant with a solar component of heat input that could contribute up to 50 MW. Twenty permit li mits were based on gross output , ranging from 833-1,100 lb CO 2 /MWhgrossg . Of these 28 permit limits, only one unit had a heat input capacity less than 1,500 MMBtu/h (the only li mit in excess of our final emission standard of 1,000 lb CO 2 /MWh-g is for a relatively small NGCC unit (base load rating of 366 MMBtu/h ); this unit also had the highest emission limit of 1, 100 lb

CO 2 /MWh. All permit limits were evaluated over an annu al period. Most of these permits included an allowance for a d esign margin to reflect the possibility that the constructed fac ility will not be able to achieve the design heat rate; an all owance) that commenced construction prior to the proposal and th us will not be subject to the requirements of this final rule. Each of the permit limits discussed above that is 1 ,000 lb

CO 2 /MWh or less includes all periods of operation, inc luding startup, shutdown and malfunction events. In additi on, each permit limit was set after backup and additional fu el use were taken into consideration. While some permits restri ct fuel use to only natural gas, others allow limited usage (du ration and type) of backup and other fuels. For example, the P ioneer Valley Energy Center has unrestricted use of natural gas, but can burn ultra-low sulfur diesel (ULSD) for up to 1,440 hour s per 12- month period. This permit requires the unit to comp ly with a*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 633 of 854 limit of 895 lb CO 2 /MWh-n even when burning up to 16 percent distillate oil. Each permit limit takes into accoun t the mode of operation for the combustion turbine. For example, the permit for the Lower Colorado River Authority's Ferguson p lant evaluated emission limits for the plant at 50, 75, and 100 percent gross load. The emission limit of 918 lb CO 2 /MWh-n accounts for the unit’s expected operation at 50 pe rcent gross load. For NGCC units with duct burners on their HRS Gs, the permit limits account for the hours of operation wi th duct burners firing. Finally, most of these permits incl ude compliance margins to account for efficiency losses due to combustion turbine degradation prior to maintenance overhauls; an allowance for the steam turbine system; and an a llowance for the variabilityand other factors (e.g., actual oper ating parameters, site-specific design considerations, an d the use of backup fuel). In total, these compliance margins re sult in operation of auxiliary plant equipment due to use o ver time. Typically, the sum of these allowances was in the r ange of a 10 to 13 percent . Limits typically increase in the permitted CO 2 emission limits, yet all of the limits except one w ere still below 1,000 lb CO 2 /MWh-g. Finally, we also reviewed NGCC design efficiency da ta and specifications submitted to Gas Turbine World. Spec ifically, we review the reported efficiency data for 88 differen t 60 Hz NGCC*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 634 of 854 units manufactured by Alstom, GE Energy Aeroderivat ive and Heavy Duty, Mitsubishi Heavy Industries, Pratt & Whitney, Rolls-Royce, and Siemens Energy. The designs ranged in model yea r from 1977 to 2011, capacities ranged from 31 to 1,026 MW, and base load ratings ranged from 236 to 3,551 MMBtu/h. The avera ge reported design emission rate for these units was 834 lb CO 2 /MWh-n and ranged from 725 to 941 lb CO 2 /MWh-n. Therefore, our optional standard of 1,030 lb CO 2 /MWh-n would allow for an average compliance margin of 24 percent, with a range from 10 to 42 percent, over the design rate. Ninety-five percent of designs would have a compliance margin of 13 percent or mor e, the top end of the range of compliance margins determined t o be appropriate in the PSD permits we reviewed.

Because some commenters were concerned that smaller NGCC units will not be able to achieve the emission stan dard, we specifically considered whether the unit would be base load or load-following. Some permits limited the amount of No. 2 fuel oil that could bethe design rates for smaller units . For the 52 small units (base load rating of 850 MMBtu/h or les s), the average design emission rate was 865 lb CO 2 /MWh and ranged from

796 to 941 lb CO 2 /MWh-n. Therefore, our optional standard of 1,030 lb CO 2 /MWh-n would allow for an average compliance margin averaged 19 percent, with a range of 10 to 29 perce nt, over the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 635 of 854 design rate. Ninety-five percent of small NGCC desi gns would have a compliance margin of 13 percent or more. We further refined our analysis by only considering the most efficient design for a given combustion turbin e engine. For example, GE Energy Aeroderivative offers four desig n options for its LM2500 model-type, all with a rating of approxi mately 45 MW. The design emission rates for these various options range from 827 to 914 lb CO 2 /MWh-n. When only the most efficient models for a particular combustion turbine engine design are c onsidered, all NGCC models have over a 13 percent compliance m argin. In other words, developers of new base load natural ga s-fired combustion turbines concerned about the achievabili ty of the final standard have multiple more efficient options offered by the same manufacturer. Therefore, we have concluded that the final emission standard allows sufficient flexibili ty for end users to select an NGCC design appropriate for thei r specific requirements. After considering these three sources of informatio n - actual NGCC emission rate data, PSD permit limits f or NGCC facilities, and NGCC design information – we have c oncluded that a standard of 1,000 lb CO 2 /MWh is both achievable and appropriate for newly constructed base load natural gas-fired c ombustion turbines. While we anticipate that the large majori ty of new NGCC units will operate well below this emission ra te, this*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 636 of 854 standard provides flexibility for developers to tak e into account site-specific conditions (e.g., ambient con ditions and cooling system), operating characteristics (e.g., p art-load operation and frequent starting and stopping), and reduced efficiency due to degredation. The standard also ac commodates the full size range of turbines. We also expect multiple technology developments to further increase the performance of new base load natural g as-fired stationary combustion turbines. Vendors continue to improve the single cycle efficiency of combustion turbines. The use of more efficient combustion turbine engines improves the o verall efficiency of NGCC facilities. In addition, existin g smaller NGCC facilities were likely designed using single o r dual pressure HRSGs without a reheat cycle. New designs can incorporate three pressure steam generators with a reheat cycle to improve the overall efficiency of the NGCC facil ity. Finally, additional technologies to reduce emission rates fo r new combustion turbines include CHP and integrated non- emitting technologies. For example, an NGCC unit that is des igned as a CHP unit where ten percent of the overall output is useful thermal output would have an emission rate approxim ately five percent less than an electric only NGCC. In sum, we believe that our final emission standards of 1,000 lb CO 2 /MWh-g and 1,030 lb*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 637 of 854

CO 2 /MW-n are not only readily achievable, but likely conservative. b. Reconstructed base load natural gas-fired units We disagree with commenters that stated that recons tructed combustion turbines will not be able to achieve the proposed emission standards. For the reasons listed below, w e have concluded that an existing base load natural-gas fi red unit that reconstructs can achieve an emission rate of 1,000 lb CO 2 /MWh-g, regardless of its size. Highly efficient NGCC units include (1) an efficien t combustion turbine engine, (2) an efficient steam c ycle, and (3) a combustion turbine exhaust system that is “matche d” to the steam cycle for maximum efficiency. In order for an existing NGCC unit to trigger the reconstruction provisions, the unit would have to essentially be entirely rebuilt. This would involve extensive upgrades to both the combustion t urbine engine and the HRSG. Therefore, a reconstructed NGCC unit will be able to maximize the efficiency of the turbine engine an d the steam cycle and match the two for maximum efficiency. According to comments submitted in response to the proposal for existing sources under CAA section 111(d), ther e are various options available to improve the efficiency of exis ting combustion turbines. One combustion turbine manufac turer provided comments describing specific technology up grades for*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 638 of 854 the compressor, combustor, and gas turbine componen ts. This manufacturer stated that operators of existing turb ines can replace older internal components along the gas pat h with stateof-the-art components that have higher aerodynamic efficiencies and improved seal designs. These gas-path enhanceme nts enable existing sources to both improve the efficiency of the turbine engine and improve the systems used as backup fuel and adjusted emission limits to account for this use. Startup an d shutdown emissions were typically included in for cooling th e metal parts along the hot-gas path to allow existing systems to achieve higher operating temperatures. In total, the manufa cturer stated that utilities deploying these gas-path improvement s on reconstructed industrial frame combustion turbines with nominal output ratings of 170 to 180 MW can increase their output by 10 MW while reducing CO 2 emissions by more than 2.6 percent compared to baseline. In addition to gas-path and software i mprovements, the manufacturer stated that the newest low-NO X combustor designs can be retrofitted on modified and reconstructed tu rbines to achieve lower NO X emissions, which improves turndown (i.e., to enable stable operations at lower loads compared to the lowest stable load achievable at baseline conditions) and efficiencies across all load conditions. The manufacturer indica ted that operators of existing combustion turbines deploying both stateof-the-art gas-path and software upgrades and combu stor upgrades*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 639 of 854 can increase output on frame-style turbines with no minal output ratings of 170 to 180 MW by 14 MW, while reducing C O 2 emissions by 2.8 percent. In addition to the preceding upgrad es, the manufacturer stated that existing combustion turbin es can achieve the largest efficiency improvements by upgr ading existing compressors with more advanced compressor technologies, potentially improving the combustion turbine's effi ciency by an additional 3.8 percent. Thus, the total potential C O 2 emissions reductions for just the combustion turbine portion of a combined cycle unit is 6.6 percent. In addition to upgrades to the combustion turbine e ngine, an operator reconstructing a NGCC unit will have th e opportunity to improve the efficiency of the HRSG and steam cyc le. For example, a steam turbine manufacturer identified th ree retrofit technologies available for reducing the CO 2 emissions rate of existing steam turbines by 1.5 to 3 percent: (1) st eam-path upgrades can minimize aerodynamic and steam leakage losses; (2) replacement of the existing high pressure turbine s tages with state-of-the-art stages capable of extracting more energy from the same steam supply; and (3) replacement of low-p ressure turbine stages with larger diameter components that extract additional energy and that reduce velocities, wear, and corrosion.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 640 of 854 In addition, an operator reconstructing a NGCC unit could upgrade the entire steam cycle. For example, combin ed cycle units originally constructed with only a single pre ssure level can be upgraded to also include second and third pr essure levels. Studies 569,570,571 show that converting a single pressure HRSG with steam reheat to a double pressure configu ration with

steam reheat can reduce the CO 2 emission rate of a NGCC unit by 1.5 to 1.7 percent. These same studies show that co nverting from a single pressure configuration with reheat to a tr iple pressure configuration with reheat can yield a 1.8 to 2 perc ent reduction in the CO 2 emission rate. Similarly, units constructed with o nly a double pressure configuration without reheat can obtain a 0.4 percent reduction by adding a reheat cycle or a 0.9 percent reduction by converting to a triple pressure config uration and adding a reheat cycle. Existing NGCC turbines that convert to these advanced HRSG configurations and that deploy the previously discussed combustion turbine and steam t urbine

569 "Exergetic and Economic Evaluation of the Effects of HRSG Configurations on the Performance of Combined Cycle Power Plants." M. Mansouri, et al. Energy Conversion and Management 58:47-58, 2012. 570 "Combined Cycle Power Plant Performance Analyses B ased on Single-Pressure and Multipressure Heat Recovery Ste am Generator." M. Raham, Journal of Energy Engineering , 138:136- 145, 2012. 571 "Thermodynamic Evaluation of Combined Cycle Plants ." N. Woudstras et al. Energy Conversion and Management 51:1099-1110, 2010.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 641 of 854 upgrades can realize CO 2 emission rate reductions ranging from 6 to 10 percent, depending on their baseline design a nd condition. Based on the available options to improve the effic iency of existing NGCC units and the fact that the vast majo rity of existing NGCC units are already achieving emission rates of 1,000 lb CO 2 /MWh-g or less, we have concluded that all reconstructed NGCC units can achieve this emission rate. Finally, we note that an owner or operator that is considering reconstructing an existing simple cycle turbine should decide how they wish to operate that turbine in the future. If they anticipate operating above the perc entage electric sales threshold, then they should install a HRSG and steam turbine and convert to a NGCC power block in accordance with our determination that NGCC is the BSER for ba se load applications. If they intend to operate the turbine below the percentage electric sales threshold, however, then the clean fuels standard, described below, will apply. c. Newly constructed and reconstructed non-base loa d natural gas-fired units The EPA agrees with the commenters who stated that “no emission limit” would be inconsistent with the requ irements of CAA 111(a)(1). We therefore are finalizing an input -based

standard based on the use of clean fuels for non-ba se load natural gas-fired combustion turbines in recognitio n that*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 642 of 854 efficiency can be reduced due to operation at low l oads, cycling, and frequent startups. The EPA has conclud ed that, at this time, we do not have sufficient information to set a meaningful output-based standard for non-base load natural gasfired combustion turbines. The input-based standard requires non-base load units to burn fuels with an average e mission rate of 120 lb CO 2 /MMBtu or less. This standard is readily achievable

because the CO 2 emission rate of natural gas is 117 lb CO 2 /MMBtu. The most common backup fuel is distillate oil, whic h has a CO 2 emission rate of 163 lb CO 2 /MMBtu. A non-base load natural gasfired combustion turbine burning 9 percent distilla te oil and 91 percent natural gas has an emission rate of 121 lb CO 2 /MMBtu, which rounds to 120 lb CO 2 /MMBtu using two significant digits. Therefore, the vast majority of owners and operator s of natural gas-fired non-base load combustion turbines will be able to achieve the standard using business-as-usual fuels. While the emission reductions that will result from restricting the use of fuels with higher CO 2 emission rates is minor, the compliance burden is also minimal. Owner s and operators of non-base load natural gas-fired combus tion turbines burning fuels with consistent chemical compositions that meet the clean fuels requirement (e.g., natural gas, eth ane, ethylene, propane, naphtha, jet fuel kerosene, dist illate oils 1 and 2, and biodiesel) will only need to maintain re cords that*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 643 of 854 they burned these fuels in the combustion turbine. No additional recordkeeping or reporting will be required. Owners and operators burning fuels with higher CO 2 emission rates and/or chemical compositions that vary (e.g., residual oil , non-jet fuel kerosene, landfill gas) will have to follow th e procedures in part 98 of this part to determine the average CO 2 emission rate of the fuels burned during the applicable 12-o peratingmonth compliance period and submit quarterly report s to verify that they are in compliance with the required emiss ion standard. d. Newly constructed and reconstructed multi-fuel-f ired units We also are finalizing an input-based standard base d on the use of clean fuels, as opposed to an output-based s tandard, for multi-fuel units for several reasons. Specifically, we do not currently have continuous CO 2 emissions data for multi-fuel-fired units, we have not evaluated the potential efficien cy impacts of different fuels, and the range of carbon content of non-natural gas fuels complicates establishing an appropriate o utput-based standard. Based on this lack of data, we have concl uded that we cannot establish an output-based emission standard for multifuel-fired combustion turbines at this time. The input-based emissions standard for this subcate gory is

based on the use of clean fuels. The use of clean f uels will ensure that newly constructed and reconstructed com bustion turbines minimize CO 2 emissions during all periods of operation*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 644 of 854 by limiting the use of fuels with higher CO 2 emission rates. To accurately represent the BSER and limit the ability of units to co-fire higher CO 2 emitting fuels with natural gas, we have concluded that it is necessary to use an equation b ased on the heat input from natural gas to determine the applic able emission standard. The 12-operating-month standard will vary from 120 lb

CO 2 /MMBtu to 160 lb CO 2 /MMBtu depending on the fraction of heat input from natural gas. The standard will be calcul ated by adding the product of the percent of heat input fro m natural gas and 120 with the product of the heat input from non -natural gas fuels and 160. For example, a combustion turbine th at burns 80 percent natural gas and 20 percent distillate oil w ould be subject to an emission standard of 130 lb CO 2 /MMBtu (rounded to two significant figures), which is equivalent to th e actual emission rate of a unit burning this combination of fuels. On the other hand, a combustion turbine that burns 100 percent residual oil would be subject to an emission standa rd of 160 lb

CO 2 /MMBtu, but would have a higher actual emission rat e, and would thus be out of compliance. In this way, the s tandard will restrict higher carbon fuels from being burned in m ulti-fuelfired units, but will be readily achievable by unit s burning

clean fuels. According to information submitted to the EIA, the primary, non-natural gas fuels used by combustion turbines t oday for the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 645 of 854 production of electricity should all meet our defin ition of a clean fuel. Thus, while the emission reductions tha t will result from restricting the use of fuels with higher CO 2 emission rates is minor, the compliance burden is also minimal. Ow ners and operators of multi-fuel-fired combustion turbines b urning fuels with consistent chemical compositions that meet the clean fuels requirement (e.g., natural gas, ethylene, propane, naphtha, jet fuel kerosene, distillate oils 1 and 2, and biodies el) will only need to maintain records that they burned these fue ls in the combustion turbine. No additional recordkeeping or reporting will be required. Owners and operators burning fuel s with higher

CO 2 emission rates and/or chemical compositions that v ary (e.g., residual oil, non-jet fuel kerosene, landfill gas) will have to follow the procedures in part 98 of this part to de termine the average CO 2 emission rate of the fuels burned during the applicable 12-operating-month compliance period and submit quarterly reports to verify that they are in compli ance with the required emission standard.

e. Modified units The EPA is not finalizing the proposed emission sta ndards for stationary combustion turbines that conduct mod ifications. As explained in Section XV below, we are withdrawin g the June 2014 proposal with respect to these sources. We rec eived a significant number of comments asserting that modif ied*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 646 of 854 combustion turbines could not meet the proposed emi ssion standards of 1,000 lb/MWh-g for large turbines and 1,100 lb/MWhg for small turbines. For the reasons explained in Section IX.B.1 above, we have decided not to subcategorize combustion turbines based on size for a number of reasons and are setting a single standard of 1,000 lb/MWh-g for all base load natural gasfired turbines instead. While we are confident that all new and reconstructed units will be able to achieve this st andard, we are less confident that all smaller combustion turb ines that undertake a modification, specifically those that w ere constructed prior to 2000, will be able to do so. U ntil we have the opportunity to further investigate the full ran ge of modifications that turbine owners and operators mig ht undertake, we consider it premature to finalize emission stand ards for

these sources. Combustion turbines have unique characteristics th at make determining an appropriate emission standard for mo dified sources a more challenging task than for coal-fired boilers. For example, each combustion turbine engine has a speci fic corresponding combustor. The development of more ef ficient combustor upgrades for existing turbine designs typ ically requires manufacturers to expend considerable resou rces. Consequently, not all manufacturers offer combustor upgrades for smaller or older designs because it would be diffic ult to recoup*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 647 of 854 their investment. In contrast, efficiency upgrades for boilers can generally be installed regardless of the specif ic boiler’s characteristics. In addition, natural gas has the lowest CO 2 emission rate (in terms of lb CO 2 /MMBtu) of any fossil fuel. As a result, an owner or operator that adds the ability to burn a b ackup fuel, such as distillate oil, to an existing turbine woul d likely trigger an NSPS modification. This is a relatively low-capitalcost upgrade that would significantly increase a un it’s potential hourly emission rate, even though the annual average compliance calculation. emissions increase would be relatively minor because operating permits generally limit the amount of distillate oil that a unit can burn. We need to con duct additional analysis to determine an appropriate emi ssion standard for units that undertake this type of modi fication, which does not involve any of the combustion turbin e components that impact efficiency. To be clear, the EPA is not reaching a final decisi on that modifications should be subject to different requir ements than we are finalizing in this rule for new and reconstr ucted sources. We have made no decisions, and this matter is not concluded. We plan to continue to gather informatio n, consider the options for modifications, and develop a new pr oposal for modifications in the future. Therefore, the EPA is withdrawing*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 648 of 854 the proposed standards for all combustion turbines that conduct modifications and is not issuing final standards fo r those sources at this time. See Section XV below. We note that the effect of this withdrawal is that modified combusti on turbines will continue to be existing sources subject to sec tion 111(d). 572 X. Summary of Other Final Requirements for Newly Co nstructed, Modified, and Reconstructed Fossil Fuel-fired Elect ric Utility Steam Generating Units and Stationary Combustion Tu rbines This section describes the final action’s requireme nts regarding startup, shutdown, and malfunction; conti nuous monitoring; emissions performance testing; continuo us compliance; and notification, recordkeeping, and re porting for newly constructed, modified, and reconstructed affe cted steam generating units and combustion turbines. We also e xplain final decisions regarding several of these requirements.

572 As discussed above in Section VI.A of this preambl e, a modified source that is not covered by a final or p ending proposed standard continues to be an “existing sour ce” and so will be covered by requirements under section 111(d ). Under the definition of “existing source” in section 111(a)(6 ), an existing source is any source that is not a new sou rce. Under the definition of “new source” in section 111(a)(2) , a modified source is a new source only if the modification occ urs after the publication of regulations (or proposed regulations , if earlier) that will be applicable to that source. Because we are not finalizing regulations with respect to modified ste am turbines, and are withdrawing the proposal with respect to su ch sources, there are neither final regulations nor pending pro posed regulations which will be applicable to such modifi cations.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 649 of 854 A. Startup, Shutdown, and Malfunction Requirements In its 2008 decision in Sierra Club v. EPA , 551 F.3d 1019 (D.C. Cir. 2008), the U.S. Court of Appeals for the District of ColumbiaD.C. Circuit vacated portions of two provisions in the EPA’s CAA section 112 regulations governing the emi ssions of hazardous air pollutants (HAP) during periods of st artup, shutdown, and malfunction (SSM). Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) an d 40 CFR 63.6(h)(1), holding that under section 302(k) of th e CAA, emissions standards or limitations must be continuo us in nature and that the SSM exemption violates the CAA's requi rement that some CAA section 112 standards apply continuously. Consistent with Sierra Club v. EPA, the EPA has established standards in this rule that apply at all times. In establishing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons e xplained

below as well as in Section V.J.1 above , has not established alternate standards for those periods. Specifically, startup and shutdown periods are included in the compliance calculation as periods of partial load. The final method to cal culate compliance is to sum the emissions for all operatin g hours and to divide that value by the sum of the electric ene rgy output (and useful thermal energy output, where applicable for affected CHP EGUs), over a rolling 12-operating-month period . In their*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 650 of 854 compliance determinations, sources must incorporate emissions from all periods, including startup or shutdown, du ring which fuel is combusted and emissions are being monitored , in addition to all power produced over the periods of emissions

measurements. GivenAs explained in Section V.J.1, given that the duration of startup or shutdown periods is expected to be small relative to the duration of periods of normal opera tion and that the fraction of power generated during periods of s tartup or shutdown is expected to be very small, the impact o f these periods on the total average over a 12-operating-mo nth period is expected to be minimal. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s opera tions. Malfunctions, in contrast, are neither predictable nor routine. Instead they are, by definition sudden, infrequent and not reasonably preventable failures of emissions contro l, process or monitoring equipment. (40 CFR 60.2). The EPA interp rets CAA section 111 as not requiring emissions that occur d uring periods of malfunction to be factored into development of s ection 111 standards. Nothing in CAA section 111 or in case la w requires that the EPA consider malfunctions when determining what standards of performance reflect the degree of emis sion limitation achievable through “the application of t he best system of emission reduction” that the EPA determin es is*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 651 of 854 adequately demonstrated. While the EPA accounts for variability in setting emissions standards, nothing in CAA sect ion 111 requires the agency to consider malfunctions as par t of that analysis. A malfunction should not be treated in th e same manner as the type of variation in performance that occurs during routine operations of a source. A malfunction is a failure of the source to perform in a “normal or usual manner” and no statutory language compels the EPA to consider such events in setting CAA section 111 standards of performance. Further, accounting for malfunctions in setting emi ssion standards would be difficult, if not impossible, gi ven the myriad different types of malfunctions that can occ ur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, de gree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable. See, e.g., Sierra Club v. EPA , 167 F.3d 658, 662 (D.C. Cir. 1999) (“The EPA typically has wide latit ude in determining the extent of data-gathering necessary to solve a problem. We generally defer to an agency's decision to proceed on the basis of imperfect scientific information, r ather than to 'invest the resources to conduct the perfect study. '") See also, Weyerhaeuser v Costle , 590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In the nature of things, no general limit, individual permit, or*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 652 of 854 even any upset provision can anticipate all upset s ituations. After a certain point, the transgression of regulat ory limits caused by ‘uncontrollable acts of third parties,’ s uch as strikes, sabotage, operator intoxication or insanit y, and a variety of other eventualities, must be a matter fo r the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation.”). In addition, emissions during a malfunction event can be signifi cantly higher than emissions at any other time of source operatio n. For example, if an air pollution control device with 99 percent removal goes off-line as a result of a malfunction (as might happen if, for example, the bags in a baghouse catc h fire) and the emission unit is a steady state type unit that would take days to shut down, the source would go from 99 perc ent control to zero control until the control device was repair ed. The source’s emissions during the malfunction would be 100 times higher than during normal operations. As such, the emissions over a 4-day malfunction period would exceed the an nual emissions of the source during normal operations. A s this example illustrates, accounting for malfunctions co uld lead to standards that are not reflective of (and significa ntly less stringent than) levels that are achieved by a well- performing, non-malfunctioning source. It is reasonable to inte rpret CAA section 111 to avoid such a result. The EPA’s appro ach to*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 653 of 854 malfunctions is consistent with CAA section 111 and is a reasonable interpretation of the statute. Given that compliance with the emission standard is determined on a 12-operating-month rolling average basis, the impact of periods of malfunctions on the total aver age over a 12-operating-month period is expected to be minimal . Thus, malfunctions over that period are not likely to res ult in a violation of the standard.

In the unlikely event that a source fails to comply with the applicable CAA section 111 standards as a resul t of a malfunction event, the EPA would determine an appro priate response based on, among other things, the good fai th efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as w ell as root cause analyses to ascertain and rectify excess emis sions. The EPA would also consider whether the source's failur e to comply with the CAA section 111 standard was, in fact, sud den, infrequent, not reasonably preventable and was not instead caused in part by poor maintenance or careless oper ation. 40 CFR 60.2 (definition of malfunction). If the EPA determines in a particular case that an enforcement action against a source for violation o f an emission standard is warranted, the source can raise any and all defenses in that enforcement action and the federal district court will*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 654 of 854 determine what, if any, relief is appropriate. The same is true for citizen enforcement actions. Similarly, the pre siding officer in an administrative proceeding can conside r any defense raised and determine whether administrative penalti es are appropriate. In summary, the EPA interpretation of the CAA and, in particular, CAA section 111 is reasonable and encou rages practices that will avoid malfunctions. Administrat ive and judicial procedures for addressing exceedances of t he standards fully recognize that violations may occur despite g ood faith efforts to comply and can accommodate those situati ons. In the January 2014 proposal for newly constructed EGUs, the EPA had proposed to include an affirmative defe nse to civil penalties for violations caused by malfunctions in an effort to create a system that incorporates some flexibility, recognizing that there is a tension, inherent in many types of air regulation, to ensure adequate compliance while sim ultaneously recognizing that despite the most diligent of effor ts, emission standards may be violated under circumstances entir ely beyond the control of the source. Although the EPA recogni zed that its case-by-case enforcement discretion provides suffic ient flexibility in these circumstances, it included the affirmative defense to provide a more formalized approach and m ore regulatory clarity. See Weyerhaeuser Co. v. Costle , 590 F.2d*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 655 of 854 1011, 1057-58 (D.C. Cir. 1978) (holding that an inf ormal caseby-case enforcement discretion approach is adequate ); but see Marathon Oil Co. v. EPA , 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more formalized approach to considerat ion of “upsets beyond the control of the permit holder”). Under the EPA’s regulatory affirmative defense provisions, if a source could demonstrate in a judicial or administrative p roceeding that it had met the requirements of the affirmative defense in the regulation, civil penalties would not be assess ed. Recently, the U.S. Court of Appeals for the District of Colum bia Circuit vacated an affirmative defense in one of the EPA’s CAA section 112 regulations. NRDC v. EPA , 749 F.3d 1055 (D.C. Cir., 2014) (vacating affirmative defense provisions in CAA sec tion 112 rule establishing emission standards for Portland cement kilns). The court found that the EPA lacked authority to establ ish an affirmative defense for private civil suits and hel d that under the CAA, the authority to determine civil penalty a mounts in such cases lies exclusively with the courts, not th e EPA. Specifically, the Court found: “As the language of the statute makes clear, the courts determine, on a case-by-cas e basis, whether civil penalties are ‘appropriate.’” See NRDC at 1063 (“[U]nder this statute, deciding whether penalties are ‘appropriate’ in a given private civil suit is a jo b for the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 656 of 854 courts, not EPA.”). 573 In light of NRDC , the EPA is not including a regulatory affirmative defense provision in this final rule. As explained above, if a source is unable to comply with emissions standards as a result of a malfunction, t he EPA may use its case-by-case enforcement discretion to prov ide flexibility, as appropriate. Further, as the D.C. C ircuit recognized, in an EPA or citizen enforcement action , the court has the discretion to consider any defense raised a nd determine whether penalties are appropriate. Cf. NRDC , at 1064 (arguments that violations were caused by unavoidable technolo gy failure can be made to the courts in future civil cases whe n the issue arises). The same is true for the presiding officer in EPA administrative enforcement actions. 574

573 The court’s reasoning in NRDC focuses on civil judicial actions. The court noted that “EPA's ability to det ermine whether penalties should be assessed for Clean Air Act violations extends only to administrative penalties , not to civil penalties imposed by a court.” Id. 574 Although the NRDC case does not address the EPA’s authority to establish an affirmative defense to penalties th at is available in administrative enforcement actions, th e EPA is not including such an affirmative defense in the final rule. As explained above, such an affirmative defense is not necessary. Moreover, assessment of penalties for violations ca used by malfunctions in administrative proceedings and judi cial proceedings should be consistent. Cf . CAA section 113(e) (requiring both the Administrator and the court to take specified criteria into account when assessing pena lties).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 657 of 854 B. Continuous Monitoring Requirements The majority of comments received on the proposal s upported the EPA's use of existing monitoring requirements u nder the Acid Rain Program, which are contained in 40 CFR part 75 requirements. In response to this, the EPA is final izing monitoring requirements that incorporate and refere nce the part 75 monitoring requirements as frequent as practicablefor the majority of the CO 2 and energy output monitoring requirements while ensuring monitoring accuracy and stringency required under the program. This final rule requires owners or operators of EGU s that combust solid fossil fuel to install, certify, main tain, and operate continuous emission monitoring systems (CEM S) to measure

CO 2 concentration, stack gas flow rate, and (if needed ) stack gas moisture content in accordance with 40 CFR part 75, in order to determine hourly CO 2 mass emissions rates (tons/hr). The rule allows owners or operators of affected EG Us that burn exclusively gaseous or liquid fuels to install fuel flow meters as an alternative to CEMS and to calculate t he hourly CO 2 mass emissions rates using Equation G-4 in Appendix G of Part 75. To implement this option, hourly measurements o f fuel flow rate and periodic determinations of the gross calor ific value (GCV) of the fuel are also required, in accordance with Appendixappendix D of Partpart 75.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 658 of 854 In addition to requiring monitoring of the CO 2 mass emission rate, the rule requires EGU owners or operators to monitor the hourly unit operating time and “gross output”, expr essed in megawatt hours (MWh). The gross output includes ele ctrical output plus any mechanical output, plus 75 percent of any useful thermal output. The rule requires EGU owners or operators to prepa re and submit a monitoring plan that includes both electro nic and hard copy components, in accordance with sections40 CFR 75.53(g) and (h). The electronic portion of the monitoring plan should be submitted to the EPA’s Clean Air Markets Division ( CAMD ) using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion of the plan shou ld be sent to the applicable Statestate and EPA Regional office. Further, all monitoring systems used to determine the CO 2 mass emission rates have to be certified according to section40 CFR 75.20 and section 6 of Partpart 75, Appendixappendix A within the 180-day window of time allotted under section40 CFR 75.4(b), and are required to meet the applicable on-going quality as surance procedures in Appendicesappendices B and D of Partpart 75. The rule requires all valid data collected and reco rded by the monitoring systems (including data recorded dur ing startup, shutdown, and malfunction) to be used in assessing compliance. Failure to collect and record required data is a vi olation of*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 659 of 854 the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monito ring system malfunctions, and required monitoring system qualit y assurance or quality control activities that temporarily inte rrupt the measurement of stack emissions (e.g., calibration e rror tests, linearity checks, and required zero and span adjust ments). The rule requires only those operating hours in whi ch valid data are collected and recorded for all of the para meters in the

CO 2 mass emission rate equation to be used for calcula ting compliance with applicable emission limits. Additio nally for EGUs using CO 2 CEMS, only unadjusted stack gas flow rate values should be used in the emissions calculations. In th is rule, Partpart 75 bias adjustment factors (BAFs) should not be ap plied to the flow rate data. These restrictions on the us e of Partpart 75 data for Partpart 60 compliance are consistent with previous NSPS regulations and revisions. Additionally if an affected EGU combusts natural gas and/or fuel oil and the CO 2 mass emissions rate are measured using Equation G-4 in Appendixappendix G of Partpart 75, then determination of site-specific carbon-bas ed Ffactors using Equation F-7b in section 3.3.6 of Appendixappendix

F of Partpart 75 is allowed, and use of these F c values in the emissions calculations instead of using the default F c values in the Equation G-4 nomenclature is also allowed.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 660 of 854 This final rule includes the following special comp liance provisions for units with common stack or multiple stack configurations; these provisions are consistent wit h section40

CFR 60.13(g):

• If two or more EGUs share a common exhaust stack, a re subject to the same emission limit, and the operato r is required to (or elects to) determine compliance usi ng CEMS, then monitoring the hourly CO 2 mass emission rate at the common stack instead of monitoring each EGU sep arately is allowed. If this option is chosen, the hourly gr oss electrical load (or steam load) is the sum of the h ourly loads for the individual EGUs and the operating tim e is expressed as “stack operating hours” (as defined in 40 CFR 72.2). Then, if compliance with the applicable emis sion limit is attained at the common stack, each EGU sha ring the stack will be in compliance with the CO 2 emissions limit.

• If the operator is required to (or elects to) deter mine compliance using CEMS and the effluent from the EGU discharges to the atmosphere through multiple stack s (or, if the effluent is fed to a stack through multiple ducts and is monitored in the ducts), then monitoring the hourly

CO 2 mass emission rate and the “stack operating time” at*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 661 of 854 each stack or duct separately is required. In this case, compliance with the applicable emission limit is determined by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross output for the unit. The rule requires 95 percent of the operating hours in each compliance period (including the compliance periods for the intermediate emission limits) to be valid hours, i. e., operating hours in which quality-assured data are collected a nd recorded for all of the parameters used to calculate CO 2 mass emissions. EGU owners or operators have the option to use back up monitoring systems, as provided in sections40 CFR 75.10(e) and 75.20(d), to help meet this data capture requirement. This requi rement is separate from the requirement for a source to demon strate compliance with an applicable emission standard. Wh en demonstrating compliance with an emission standard the calculation must use all valid data to calculate a compliance average even if the percent of valid hours recorded in the period is less than the 95 percent requirement. C. Emissions Performance Testing Requirements Similarly to the comments received on monitoring fo r the proposal, commenters in general supported the use o f current testing requirements required under the Acid Rain P rogram 40 CFR part 75 requirements. Thus the EPA is finalizing requirements*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 662 of 854 for performance testing as consistent with part 75 requirements where appropriate to ensure the quality and accurac y of data and measurements as required by the final rule. In accordance with section40 CFR 75.64(a), the final rule requires an EGU owner or operator to begin reportin g emissions data when monitoring system certification is comple ted or when the 180-day window in section40 CFR 75.4(b) allotted for initial certification of the monitoring systems expires (wh ichever date is earlier). For EGUs subject to the 1,400 lb CO 2 /MWh- grossg ) emission standard, the initial performance test con sists of the first 12 operating months of data, starting with th e month in which emissions are first required to be reported. The initial 12-operating-month compliance period begins with th e first month of the first calendar year of EGU operation in whic h the facility exceeds the capacity factor applicability threshold. The traditional 3-run performance tests (i.e., stac k tests) described in section40 CFR 60.8 are not required for this rule. Following the initial compliance determination, the emission standard is met on a 12-operating-month rolling ave rage basis. D. Continuous Compliance Requirements ThisCommenters supported the use of a 12-operating- month rolling average for the compliance period for the f inal standards. In response, this final rule specifies that compliance with the 1,400 lb CO 2 /MWh- grg emission limit is*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 663 of 854 determined on a 12-operating-month rolling average basis, updated after each new operating month. For each 12 -operatingmonth compliance period, quality-assured data from the certified Part 75 monitoring systems is used together with th e gross output over that period of time to calculate the av erage CO 2 mass emissions rate. The rule specifies that the first operating month i ncluded in the initial 12-operating-month compliance period is the month in which reporting of emissions data is required to begin under section40 CFR 75.64(a), i.e., either the month in which monitoring system certification is completed or the month in which the 180-day window allotted to finish certifi cation testing expires (whichever month is earlier). Initial compliance with the applicable emissions li mit in kg/MWh is calculated by dividing the sum of the hou rly CO 2 mass emissions values by the total gross output for the 12-operatingmonth period. Affected EGUs continue to be subject to the standards and maintenance requirements in the CAA s ection 111 regulatory general provisions contained in 40 CFR p art 60, subpart A. Several commenters stated that the final rule shoul d require operators to round their calculated emissio ns rates to three significant figures when comparing their actu al rates to the standard. These commenters said that allowing u se of only*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 664 of 854 two significant digits when calculating the 12-oper ating-month rolling average emission rate would constitute rela xation of the standard by 5 percent because an actual emission ra te of 1,049.9

lb CO 2 /MWh rounds to 1,000 lb of CO 2 per MWh when only two significant figures are required in the final step of compliance calculations. Commenters also suggested that the em ission limits be written in scientific notation (e.g., 1.10 x 10^ 3 lb CO 2 /MWh) to clarify the number of significant digits that sh ould be used when evaluating compliance. Other commenters sugges ted that the final step in compliance calculations should reflec t rounding the emission rate to the nearest whole number using the ASTM rounding convention (ASTM E29). The General Provisions of Part 60 specify the round ing conventions for compliance calculations at 40 CFR 6 0.13(h)(3) including the provision that "after conversion into units of the standard, the data may be rounded to the same numbe r of significant digits used in the applicable subpart t o specify the emission limit." The final rule requires that the 12-operating-month rolling average emission rate must be rounded to three sign ificant figures if the applicable emissions standard is gre ater than or equal to 1,000 (e.g., an actual emission rate of 1, 004.9 lb

CO 2 /MWh is rounded to 1,000 lb CO 2 /MWh); for standards of 1000 or less, the final rule requires rounding the actual e mission rate*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 665 of 854 to two significant figures (e.g., an actual emissio n rate of 454.9 kg CO 2 /MWh is rounded to 450 kg CO 2 /MWh). Historically, many of the emissions limits under part 60 have bee n expressed to two significant digits (e.g., the original SO 2 emission standard for coal-fired units under Subpart D was 1 .2 lb

SO 2 /MMBtu). The rounding conventions under the General Provisions allow the reporting of all emission rates in the ra nge from 1.15 to 1.249 as 1.2 lb SO 2 /MMBtu. During compliance periods with emissions at the lower end of this range, the opera tor is required to report higher emissions than actually o ccurred; during compliance periods at the upper end of this range the operator is allowed to report lower emissions than actually occurred. In either case the absolute error remains small because the emission rate in this example is a rela tively small numerical value. In addition, the required emission reductions typically are large enough that rounding does not i mpact the emission control strategy of affected units. Howeve r, the final

standards for CO 2 emissions include numerical values that are larger than many historical emissions standards and require a relatively small percent reduction in emissions. Ac cordingly, it is appropriate to require the use of three signific ant digits when completing compliance calculations resulting i n numerical values larger than 1,000. This is particularly impo rtant when considering the relatively small emission rate chan ges that may*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 666 of 854 be required for compliance with the unit-specific e mission standards being finalized for modified steam genera ting and IGCC units because a rounding error of 5 percent may be larger than the percent difference between the affected unit's historically best emission rate and the emission rate immediatel y preceding the modification. The final rule requires rounding of emission rates with numerical values greater than or equal to 1,000 to three significant figures and rounding of rates with nume rical values less than 1,000 to two significant figures. E. Notification, Recordkeeping, and Reporting Requi rements ThisCommenters supported the coordination of notifi cation, recordkeeping, and reporting required under this ru le in conjunction with the requirements already in place under part 75, so the EPA has made the requirements as efficie nt and streamlined as possible with the current requiremen ts under part

75. The final rule requires an EGU owner or operator to co mply with the applicable notification requirements in section40 CFR 75.61, sections40 CFR 60.7(a)(1) and (a)(3), and section40 CFR 60.19. The rule also requires the applicable record keeping requirements in subpart F of part 75 to be met. For EGUs using CEMS, the data elements that are recorded include, among others, hourly CO 2 concentration, stack gas flow rate, stack gas mois ture content (if needed), unit operating time, and gross electric*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 667 of 854 generation. For EGUs that exclusively combust liqui d and/or gaseous fuel(s) and elect to determine CO 2 emissions using Equation G-4 in Appendixappendix G of Partpart 75, the key data elements in subpart F that are recorded include hou rly fuel flow rates, fuel usage times, fuel GCV, gross electric g eneration. The rule requires EGU owners or operators to keep r ecords of the calculations they perform to determine the t otal CO 2 mass emissions and gross output for each operating month . Records of the calculations performed to determine the average CO 2 mass emission rate (kg/MWh) and the percentage of valid CO 2 mass emission rates in each compliance period are requir ed to be kept. The rule also requires sources to keep record s of calculations performed to determine site-specific c arbon-based F-factors for use in Equation G-4 of Partpart 75, Appendixappendix G (if applicable). Sources are required to keep all records for a peri od of 3 years. All required records must be kept on-site fo r a minimum

of 2two years, after which the records can be maintained o ffsite. The rule requires all affected EGU owners/operators to submit quarterly electronic emissions reports in ac cordance with subpart G of Partpart 75. The reports in Appendixappendix G that do not include data required to calculate complianc e with the applicable CO 2 emission standard are not required to be reported*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 668 of 854 under this rule. The rule requires the reports in section40 CFR 60.5555 to be submitted using the ECMPS Client Tool . Except for a few EGUs that may be exempt from the Acid Rain Pr ogram (e.g., oil-fired units), this is not a new reporting requi rement. Sources subject to the Acid Rain Program are alread y required to report the hourly CO 2 mass emission rates that are needed to assess compliance with this rule. Additionally, in the final rule and as part of an a gencywide effort to streamline and facilitate the report ing of environmental data, the rule requires selected data elements that pertain to compliance under this rule, and tha t serve the purpose of identifying violations of an emission st andard, to be reported periodically using ECMPS. Specifically, EGU owners/operators must submit quar terly electronic reports within 30 days after the end of each quarter consistent with current Partpart 75 reporting requirements. The first report is for the quarter that includes the f inal (12 th ) operating month of the initial 12-operating-month c ompliance period. For that initial report and any subsequent report in which the 12 th operating month of a compliance period (or periods) occurs during the calendar quarter, the av erage CO 2 mass emissions rate (kg/MWh) is reported for each compli ance period, along with the dates (year and month) of the first and twelfth operating months in the compliance period and the p ercentage of*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 669 of 854 valid CO 2 mass emission rates obtained in the compliance per iod. The dates of the first and last operating months in the compliance period clearly bracket the period used i n the determination, which facilitates auditing of the da ta. Reporting the percentage of valid CO 2 mass emission rates is necessary to demonstrate compliance with the requirement to obta in valid data for 95 percent of the operating hours in each compl iance period. Any violations that occur during the quarter are id entified. If there are no compliance periods that end in the qua rter, a definitive statement to that effect must be include d in the report. If one or more compliance periods end in th e quarter but there are no violations, a statement to that effect must be included in the report. Currently, ECMPS is not programmed to receive the additional information included in the report requi red under section40 CFR 60.5555(a)(2) for affected EGUs. However, we will make the necessary modifications to the system in o rder to fully implement the reporting requirements of this rule u pon promulgation.

XI. Consistency between BSER Determinations for This Ru le and the Rule for Existing EGUs In the CAA section 111(d) rule for existing steam u nits and combustion turbines that the EPA is promulgating at the same time as this CAA section 111(b) rule, the EPA is id entifying as*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 670 of 854 part of the BSER for those sources, building block 1 (for steam units, efficient operation), building block 2 (for steam units, dispatch shift to existing NGCC units), and buildin g block 3 (for steam units and combustion turbines, substitut ion of generation with new renewable energy). In this sect ion, we explain why the EPA is not identifying building blo cks 1, 2, or 3 as part of the BSER for new, modified, or reconst ructed steam generators or combustion turbines. A. Newly Constructed Steam Generating Units 1. Preference for Technological Controls as the BSE R for New

EGUs As discussed in this preamble and in more detail in the preamble to the CAA section 111(d) rule for existin g sources, the phrase “system of emission reduction” is undefi ned and provides the EPA with discretion in setting a stand ard of performance under CAA section 111(b) or emission gu idelines under CAA section 111(d). Because the phrase by its plain language does not limit our review of potential sys tems in either context, the same systems could be considere d for application in new and existing sources. That said, many other factors and considerations direct us to focus on di fferent systems when establishing a standard of performance under CAA section 111(b) and an emission guideline under CAA section 111(d). Thus, it is useful to describe part of the underlying*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 671 of 854 basis for the BSER – partial CCS - that the EPA has determined for new steam units before discussing the building blocks that form the BSER for existing units. For new steam generating units, the EPA is identify ing, as the BSER, systems of emission reduction that assure that these sources are inherently low-emitting at the time of construction. The following reasons support this approach to the BSER. New sources are expected to have long operating liv es over which initial capital costs can be amortized. Thus, new construction is the preferred time to drive capital investment in emission controls. In this case, the BSER for ne w steam generators, partial CCS, requires substantial capit al expenditures, which new sources are best able to ac commodate. While CAA section 111(b)(1)(B) and (a)(1) by their terms do

not mandate that the BSER assure that new sources a re inherently low emitting, that approach to the BSER is consiste nt with the legislative history. 575 See Section III.H.3.b.4 above. For instance, the 1970 Senate Committee Report explains that “[t]he

575 Although Congress expressed a clear preference tha t new sources would be “designed, built, equipped, operat ed, and maintained so as to reduce emissions to a minimum,” the Senate Committee Report also makes clear that the term sta ndard of performance “refers to the degree of emission contr ol which can be achieved through process changes, operation chan ges, direct emission control, or other methods .” Sen. Rep. No. 91-1196 at 15-17, 1970 CAA Legis. Hist. at 415-17 (emphasis ad ded).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 672 of 854 overriding purpose of this section [concerning new source performance standards] would be to prevent new air pollution problems, and toward that end, maximum feasible control of new

sources at the time of their construction is seen by the committee as the most effective and, in the long ru n, the least expensive approach.” 576 Existing sources, on the other hand, would be regulated through emission standards, whic h were broadly understood at the time to reflect available technology, alternative methods of prevention and control, alte rnative fuels, processes, and operating methods. 577,578 2. Practical Implications of Including the Building Blocks Several practical considerations make the building blocks inappropriate for new sources. Thus, for the follow ing reasons,

576 Sen. Rep. No. 91-1196 at 15-16, 1970 CAA Legis. Hi st. at 416 (emphasis added). 577 See 1970 CAA Amendments, Pub. L. 91-604, § 4, 84 Stat. 1676, 1679 (Dec. 31, 1970) (describing information that t he EPA must issue to the states and appropriate air pollution c ontrol agencies along with the issuance of ambient air qua lity criteria under Section 4 of the 1970 CAA titled “Ambient Air Quality and Emission Standards”). 578 In the 1977 CAA Amendments, Congress revised secti on 111(a)(1) to mandate that the EPA base standards fo r new sources on technological controls, but, at the same time, m ade clear that the EPA was not required to base the emission guidelines for existing sources on technological controls. In the 1990 CAA Amendments, Congress repealed the section 111(a)(1) requirements that distinguished between new and existing sources and largely restored the 1970 CAA Amendments version of section 111(a)(1).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 673 of 854 the EPA does not consider it appropriate to include the building blocks as part of the BSER for new sources: a. Additional cost Partial CCS will impose substantial (albeit reasona ble) costs on new steam-generating EGUs, and, as a resul t, the EPA does not believe that including additional measures as part of the BSER would be appropriate. One disadvantage in adding additional costs is that doing so would make it mor e difficult for new steam-generating EGUs to compete with new n uclear units. Because the BSER is selected after considering cost (among other factors), the EPA is not required to, 579 and in this case believes it would not be appropriate to, select the most stringent adequately demonstrated system of emissio n reduction (through the combination of partial CCS and the bui lding blocks) for purposes of setting a standard of performance u nder CAA section 111(b).

579 For example, as early as a 1979 NSPS rulemaking fo r affected EGUs, the EPA recognized that it was not required t o establish as the BSER the most stringent adequately demonstra ted system of emission reduction available, and instead could wei gh the amount of additional emission reductions against the costs

. See 44 F.R. 52792, 52798 (Sept. 10, 1979) (“Although there may be emission control technology available that can reduce emissi ons below those levels required to comply with standards of p erformance, this technology might not be selected as the basis of standards of performance due to costs associated with its use

. Accordingly, standards of performance should not be viewed as the ultimate in achievable emission control. In fac t, the Act requires (or has potential for requiring) the impos ition of a more stringent emission standard in several situati ons.”).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 674 of 854 Building block 1 measures are not appropriate (or w ould be redundant) because the BSER for new steam generatin g units is based on highly efficient supercritical technology, i.e., stateof-the-art, efficient equipment. See Section V.K ab ove. Accordingly, there is little improvement in efficie ncy that can be justified as part of the BSER. Building block 2 and 3 measures are not appropriate for the BSER because new steam units would have a significa ntly limited range of options to implement building blocks 2 and 3. The new source performance standard was proposed and is bei ng finalized as a rate-based standard. Thus, if building blocks 2 and 3 were included in the BSER, a more stringent rate-based s tandard would be applicable to all new sources. However, it is co nceivable that the EPA could propose a hybrid standard that w ould include both an emission-rate limit that reflects partial C CS and a requirement for allowances that reflects building b locks 2 and 3. Accordingly, the following discussion assumes ei ther a ratebased or mass-based standard, or part of a hybrid s tandard. In both a rate-based program and a mass-based progr am, building blocks 2 and 3 measures can be implemented through a range of methods, including trading with other EGUs . While it is not necessarily the case that every existing source will be able to implement each of the methods, in general, exist ing sources will have a range of measures to choose from. Howev er, at least*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 675 of 854 some of those methods may not be available to new s ources, which would render compliance with their emission limits more challenging and potentially more costly. One example is emission trading with other affected EGUs. For existing sources, emission trading is an import ant option for implementing the building blocks. There are lar ge numbers of existing sources, and they will become subject to t he section 111(d) standards of performance at the same time. I t may be more cost-effective for some to implement the building b locks than others, and, as a result, some may over-comply and some may under-comply, and the two groups may trade with eac h other. Because of the large numbers of existing sources, t he trading market can be expected to be robust. Trading optimi zes efficiency. As a result, existing sources have more flexibility in the overall amount of their investment in buildi ng blocks 2 and 3 and can adjust investment obligations among t hemselves through emissions trading. In contrast, new sources construct one at a time, a nd it is unknown how many new sources there will be. Without a sizeable number of new sources, there will not be a robust t rading market. Thus, a new source cannot count on being ab le to find a new source trading partner. In addition, it is not possible to count on new sources being able to trade with exist ing sources, for several reasons. First, as noted, there are ind ications in*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 676 of 854 the legislative history that new sources should be wellcontrolled at the source, which casts doubt on whet her new sources should be allowed to meet their standards t hrough the purchase of emission credits. Second, new sources m ust meet their standards of performance as soon as they begi n operations. If they do so before the year 2022, when existing s ources become subject to section 111(d) state plan standards of p erformance, no existing sources will be available as trading pa rtners. In addition, for section 111(d) sources, we are gra nting a 7-year period of lead-time for the implementation o f the building blocks. This is due, in part, to the benef its of allowing the ERC and allowance markets to develop. However, the new source standards take effect immediately, so ne w sources would not have the advantage of this lead time were they subject to more stringent standards that also reflected the building

blocks. 580 In addition, if there are an unexpectedly large num ber of new sources, then they would be obliged to invest i n greater amounts of building blocks 2 and 3, and that could reduce the

580 At least in theory, we could consider promulgating a standard of performance for new affected EGUs that becomes m ore stringent beginning in 7 years, based on a more stringent BSE R. We are not inclined to adopt that approach because section 111 (b)(1)(B) requires that we review and, if necessary, revise t he section 111(b) standards of performance no later than every 8 years anyway.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 677 of 854 amounts of building blocks 2 and 3 available for ex isting sources, and thereby raise the costs of building bl ocks 2 and 3 for existing sources. This could compromise the BSE R under section 111(d) and undermine the ability of existin g sources to comply with their section 111(d) obligations. 581

B. New Combustion Turbines For new combustion turbines, the building blocks ar e not appropriate as part of the BSER either. Building bl ock 1 is limited to steam generating units, and therefore ha s no applicability to new combustion turbines. Measures comparable to those in building block 1 would not be appropriate because new highly efficient NGCC construction already entails high efficiency equipment and operation. Building block 2 is also limited to steam generating units and is not approp riate as part of the BSER for new NGCC units because it would not result in any emission reductions. The reasons why building block 3 are not appropriat e are the same as discussed above for why building blocks 2 and 3 are not appropriate for new steam generating units (lim ited range of

581 The EPA is authorized to consider the BSER for new and existing sources in conjunction with each other. In the 1977 CAA Amendments, Congress revised section 111(a)(1) to r equire technological controls for new combustion sources a t least in part because this requirement would preclude new so urces from relying on low-sulfur coal to achieve their emissio n limits, which, in turn, would free up low-sulfur coal for e xisting sources.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 678 of 854 options for implementation (including lack of avail ability of trading), lack of lead-time for implementation, and the possibility of reducing the availability of renewab le energy for existing sources). C. Modified and Reconstructed Steam and NGCC Units For modified and reconstructed steam generators, th e EPA identified the BSER as maintenance of high efficien cy or implementation of a highly efficient unit. The resu lting emission limit must be met over the specified time period and cannot be deviated from or averaged. As a result, a modified or reconstructed steam generator generally will requir e ongoing maintenance and may find it prudent to operate belo w its limit as a safety margin. This represents a substantial c ommitment of resources. For these units, the additional costs of implementing the building blocks would not be appropriate. In addition, building block 1 is not appropriate fo r modified or reconstructed steam generating units be cause the BSER for these units is already based on highly eff icient performance. For the same reasons, it does not make sense to attempt to develop the analogue to building block 1 for reconstructed NGCC units – the BSER for them, too, is already based on highly efficient performance. Building block 2 is not appropriate for reconstruct ed NGCC units because it would not yield any reductions.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 679 of 854 Building blocks 2 and 3 are not appropriate for mod ified or reconstructed steam generators, and building block 3 is not appropriate for reconstructed NGCC units, for the s ame reasons that they are not appropriate for new EGUs, as desc ribed above (limited range of options for implementation (inclu ding lack of availability of trading), lack of lead-time for imp lementation, and the possibility of reducing the availability of renewable energy for existing sources).

XII. Interactions with Other EPA Programs and Rules A. Overview This final rule will, for the first time, regulate GHGs under CAA section 111. In Section IX of the preambl e to the proposed rule, the EPA addressed how regulation of GHGs under CAA section 111 could have implications for other E PA rules and for permits written under the CAA Prevention of Sig nificant Deterioration (PSD) preconstruction permit program and the CAA Title V operating permit program. The EPA proposed to adopt provisions in the regulations that explicitly addre ssed some of these implications. For purpose of the PSD program, the EPA is finaliz ing provisions in part 60 of its regulations that make clear that the threshold for determining whether a PSD source must satisfy

the Best Available Control Technology ( BACT ) requirement for greenhouse gasesGHGs continues to apply after promulgation of*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 680 of 854 this rule. This rule does not require any additiona l revisions to State Implementation Plans. As discussed further below, this final rule may have bearing on the determination of BACT for new and existing and, modified , and reconstructed EGUs that require PSD permits. With respect to the Title V operating permits program, this rule does not affect whether sources are subject to the requirement to obtain a titleTitle V operating permit based solely on emitting or having the potential to emit GHGs above major source thresholds. However, this rule d oes have some implications for titleTitle V fees, which the EPA is addressing in this final rule. Finally, the fossil fuel-fired EGUs covered in this rule are or will be potentially impacted by several othe r recently finalized or proposed EPA rules, and such potential interactions with other EPA rules are discussed below. B. Applicability of Tailoring Rule Thresholds under the PSD Program In our January 8, 2014 proposal, the EPA proposed t o adopt regulatory language in 40 CFR part 60 that would en sure the promulgation of this NSPS would not undercut the ap plication of rules that limit the application of the PSD permitt ing program requirements to only the largest sources of GHGs. A n intervening decision of the United States Supreme Court has, to a large extent, resolved the legal issue that led the EPA t o propose*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 681 of 854

these Partpart 60 provisions. The Supreme Court has since clarified that the PSD program does not apply to sm aller sources based on the amount of GHGs they emit. However, bec ause the largest sources emitting GHGs remain subject to the PSD permitting requirements, the EPA has concluded that it remains appropriate to adopt the proposed regulatory provis ions in 40 CFR part 60 in this rule. We discuss our reasons fo r this action in detail below. Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassi fiable for NAAQS pollutants, a new or modified source that emi ts any air pollutant subject to regulation at or above specifi ed thresholds is required to obtain a preconstruction permit. Thi s permit assures that the source meets specific requirements , including application of BACT to each pollutant subject to re gulation under the CAA. Many states (and local districts) ar e authorized by the EPA to administer the PSD program and to iss ue PSD permits. If a state is not authorized, then the EPA issues the PSD permits for facilities in that state. To identify the pollutants subject to the PSD permi tting program, EPA regulations contain a definition of th e term “regulated NSR pollutant.” 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition contains four subpar ts, which cover pollutants regulated under various parts of t he CAA. The*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 682 of 854 second subpart covers pollutants regulated under se ction 111 of the CAA. The fourth subpart is a catch-all provisio n that applies to “[a]ny pollutant that is otherwise subje ction to regulation under the Act.” This definition and the associated PSD permitting requirements applied to GHGs for the first time on January 2, 2011, by virtue of the EPA’s regulation of GHG emissions from motor vehicles, which first took effect on that sam e date. 75 FR 17004 (Apr. 2, 2010). As such, GHGs became subject to regulation under the CAA and the fourth subpart of the “regula ted NSR pollutant” definition became applicable to GHGs. On June 3, 2010, the EPA issued a final rule, known as the Tailoring Rule, which phased in permitting requirem ents for GHG emissions from stationary sources under the CAA PSD and titleTitle V permitting programs (75 FR 31514). Under its understanding of the CAA at the time, the EPA belie ved the Tailoring Rule was necessary to avoid a sudden and unmanageable increase in the number of sources that would be req uired to obtain PSD and titleTitle V permits under the CAA because the sources emitted GHGs emissions over applicable majo r source and major modification thresholds. In Step 1 of the Tai loring Rule, which began on January 2, 2011, the EPA limited app lication of

PSD or titleTitle V requirements to sources of GHG emissions only if the sources were subject to PSD or titleTitle V “anyway”*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 683 of 854 due to their emissions of non-GHG pollutants. These sources are referred to as “anyway sources.” In Step 2 of the T ailoring Rule, which began on July 1, 2011, the EPA applied the PSD and titleTitle V permitting requirements under the CAA to sources that were classified as major, and, thus, required to obtain a permit, based solely on their potential GHG emissio ns and to modifications of otherwise major sources that requi red a PSD permit because they increased only GHG emissions ab ove applicable levels in the EPA regulations. In the PSD program, the EPA implemented the steps o f the Tailoring Rule by adopting a definition of the term “subject to regulation.” The limitations in Step 1 of the Tailo ring Rule are reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR 51.166(b)(48)(iv). With respect to “anyway sources” covered by PSD during Step 1, this provision established that greenhouse gasesGHGs would not be subject to PSD requirements unless th e source emitted GHGs in the amount of 75,000 tons pe r year (tpy) of carbon dioxide equivalent (CO 2 e) or more. The primary practical effect of this paragraph is that the PSD BACT requirement does not apply to GHG emissions from an “anyway source” unless the source emits GHGs at or above th is threshold. The Tailoring Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These provisi ons contain thresholds that, when applied through the definitio n of*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 684 of 854 “regulated NSR pollutant,” function to limit the sc ope of the terms “major stationary source” and “major modifica tion” that determine whether a source is required to obtain a PSD permit. See e.g. 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 5 1.166(b)(1); 40 CFR 51.166(b)(2). This structure of the EPA’s PSD regulations created questions regarding the extent to which the limitat ions in the Tailoring Rule would continue to apply to GHGs once they became regulated, through this final rule, under section 1 11 of the CAA. 79 FR at 1487-1488. As discussed above, the definition of “regulated NSR pollutant” in the PSD regulations co ntains a separate PSD trigger for air pollutants regulated u nder the NSPS, 40 CFR 51.166(b)(49)(ii) (the “NSPS trigger p rovision”). Thus, when GHGs become subject to a standard promul gated under CAA section 111 for the first time under this rule, PSD requirements would presumably apply for GHGs on an additional basis besides through the regulation of GHGs from m otor vehicles. However, the Tailoring Rule, on the face of its regulatory provisions, incorporated the revised thr esholds it promulgated into only the fourth subpart of the PSD definition of regulated NSR pollutant (“[a]ny pollutant that o therwise is subject to regulation under the Act”). The regulato ry text does not clearly incorporate the thresholds into the NSP S trigger provision in the second subpart (“[a]ny pollutant t hat is*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 685 of 854 subject to any standard promulgated under section 1 11 of the Act”). For this reason, a question arose as to whet her the Tailoring Rule limitations would continue to apply to the PSD requirements after they are independently triggered for GHGs by the NSPS that the EPA is now promulgating. Stakehol ders questioned whether the EPA must revise its PSD regu lations –- and, by the same token, whether states must revise their SIPs –- to assure that the Tailoring Rule thresholds will c ontinue to apply to sources potentially subject to PSD under t he CAA based on GHG emissions. In the January 8, 2014 proposed rule, the EPA expla ined that the agency had included an interpretation in the Ta iloring Rule preamble, which means that the Tailoring Rule thres holds continue to apply if and when the EPA promulgates r equirements under CAA section 111. 79 FR at 1488 (citing 75 FR 31582). Nevertheless, to ensure there would be no uncertain ty as to this issue, the EPA proposed to adopt explicit language in sections40

CFR 60.46Da(j), 40 CFR 60.4315(b), and 40 CFR 60.5515 of the agency’s regulations. The proposed language makes clear that the thresholds for GHGs in the EPA’s PSD definition of “subject to regulation” apply through the second subpart of the definition of “regulated NSR pollutant” to GHGs regulated unde r subparts Da, KKKK, and TTTT of part 60this rule

.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 686 of 854 The EPA received comments supporting the adoption o f this proposed language, but several commenters also expr essed concern that adding this language to part 60 alone would no t be sufficient. Several commenters urged the EPA to instead revise the PSD regulations in parts 51 and 52. In addition , commenters expressed concern that further steps were needed to amend the SIPs before there would be certainty that the Tailo ring Rule limitations continued to apply after the adoption o f GHGCO 2 standards under CAA section 111 in this final rule. On June 23, 2014, the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection Ag ency , issued a decision addressing the application of PSD permit ting requirements to GHG emissions. The Supreme Court he ld that the EPA may not treat GHGs as an air pollutant for purp oses of determining whether a source is a major source (or modification thereof) for the purpose of PSD applicability. The Court also said that the EPA could continue to require that PS D permits, otherwise required based on emissions of pollutants other than GHGs, contain limitations on GHG emissions based on the application of BACT. The Supreme Court decision eff ectively upheld PSD permitting requirements for GHG emission s under Step 1 of the Tailoring Rule for "anyway sources" and in validated application of PSD permitting requirements to Step 2 sources based on GHG emissions. The Court also recognized t hat, although*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 687 of 854

the EPA had not yet done so, it could “establish an ap propriate de minimis threshold below which BACT is not required for a source’s greenhouse gas emissions.” 134 S. Ct. at 2 449. In accordance with the Supreme Court decision, on A pril 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) issued an amended judgme nt vacating the regulations that implemented Step 2 of the Tail oring Rule, but not the regulations that implement Step 1 of th e Tailoring Rule. The court specifically vacated sections40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA’s regulations, but did not vacate sections40 CFR 51.166(b)(48)(iv)

or 40 CFR 52.21(b)(48)(iv). The court also directed the EPA t o consider whether any further revisions to its regul ations are appropriate in light of UARG v. EPA , and, if so, to undertake such revisions. The practical effect of the Supreme Court’s clarifi cation of the reach of the CAA is that it eliminates the need for Step 2 of the Tailoring Rule and subsequent steps of the G HG permitting phase in that the EPA had planned to consider under the Tailoring Rule. This also eliminates the possibilit y that the promulgation of GHG standards under section 111 cou ld result in additional sources becoming subject to PSD based so lely on GHGs, notwithstanding the limitations the EPA adopted in the Tailoring Rule. However, for an interim period, the EPA and t he states*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 688 of 854 will need to continue applying parts of the PSD def inition of “subject to regulation” to ensure that sources obta in PSD permits meeting the requirements of the CAA. The CAA continues to require that PSD permits issue d to “anyway sources” satisfy the BACT requirement for G HGs. Based on the language that remains applicable under sections40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv), the EPA and states may continue to limit the application of BAC T to GHG emissions in those circumstances where a source emi ts GHGs in the amount of at least 75,000 tpy on a CO 2 e basis. The EPA’s intention is for this to serve as an interim approa ch while the EPA moves forward to propose a GHG Significant Emis sion Rate (SER) that would establish a de minimis threshold level for permitting GHG emissions under PSD. Under this fort hcoming SER rule, the EPA intends to propose restructuring the GHG provisions in its PSD regulations so that the de minimis threshold for GHGs will not reside within the defin ition of “subject to regulation.” This restructuring will be designed to make the PSD regulatory provisions on GHGs universa lly applicable, without regard to the particular subpar ts of the definition of “regulated NSR pollutant” that may co ver GHGs. Upon promulgation of the SERthis PSD rule, it will then provide a framework that states may use when updating their SIPs consistent with the Supreme Court decision.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 689 of 854 While the GHG SERPSD rulemaking described above is pending, the EPA and approved state, local, and tribal permi tting authorities will still need to implement the BACT r equirement for GHGs. In order to enable permitting authorities to continue applying the 75,000 tpy CO 2 e threshold to determine whether BACT applies to GHG emissions from an “anyway source” af ter GHGs are subject to regulation under CAA section 111, the EP A has concluded that it continues to be appropriate to ad opt the proposed language in sections 60.46Da(j), 60.4315(b), and 60.5515.40 CFR 60.5515 (subpart TTTT). Because the EPA is not finalizing the proposed regulations in subparts Da and KKKK, it is not necessary to adopt the comparable provisions that the EPA proposed in 40 CFR 60.46Da(j) and 40 CFR 60.4315(b)

The EPA has evaluated these provisions40 CFR 60.5515 in light of the Supreme Court decision and the comment s received on the question of whether this CAA section 111 standa rd will undermine the application of the Tailoring Rule lim itations. While most of the Tailoring Rule limitations are no longer needed to avoid triggering the requirement to obtai n a PSD permit based on GHGs alone, the limitation in sections40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv) will remain important to provide an interim applicability level for the GHG BACT requirement in “anyway source” PSD permits. Th us, there continues to be a need to ensure that the regulatio n of GHGs*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 690 of 854 under CAA section 111 does not make this BACT appli cability level for anyway sources effectively inoperable. Th e language the EPA proposed for sections 60.46Da(j), 60.4315(b ), andin 40

CFR 60.5515 will continue to be effective at avoiding this result after the judicial actions described above a nd the adoption of this final rule. The provisions in part 60 reference sections40 CFR 51.166(b)(48) and 40 CFR 52.21(b)(49) of the EPA’s regulations. However, the courts have now vac ated sections40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v), and the EPA will take steps soon to eliminate these sub parts from the CFR. As a result of these steps, the language in 60.46Da(j), 60.4315(b), andof final 40 CFR 60.5515 will not incorporate the vacated parts of sections40 CFR 51.166(b)(48) and 40 CFR 52.21(b)(49), but these provisions in part 60 will continue to apply to those subparts of the PSD rules that are n eeded on an interim basis to limit application of BACT to GHGs only when emitted by an anyway source in amounts of 75,000 tp y CO 2 e or more. Thus, in this final rule, the EPA is adopting the proposed

text of sections 60.46Da(j), 60.4315(b), and40 CFR 60.5515 for this purpose without substantial change. As to the concern expressed by some commenters that revisions to part 60 alone are not sufficient, the GHG SER rulemaking described above will include proposed re visions to the PSD regulations in parts 51 and 52 that should ultimately*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 691 of 854 address this concern. The EPA acknowledges that the commenters concern will not be fully addressed for an interim period of time, but (for the reasons discussed above) the par t 60 provisions adopted in this rule are sufficient to m ake explicit that the 75,000 tpy CO 2 e BACT applicability level for GHGs will apply to GHGs that are subject to regulation under the CAA section 111 standards adopted in this rule. Rather than adopting a temporary patch in its PSD regulations in this rule to address the implication s for PSD of regulating GHGs under CAA section 111, the EPA beli eves it will be most efficient for the EPA and the states if the EPA completes a comprehensive PSD rule that will addres s all the implications of the Supreme Court decision. The rev isions the EPA will consider based on the Supreme Court decisi on will inherently address the commenters concerns about th e definition of the “subject to regulation” and the proposed par t 60 provisions. To the extent this PSD rule is not comp lete before the EPA proposes additional CAA section 111 standar ds for GHGs, the EPA will need to consider adding provisions lik e sections 60.46Da(j), 60.4315(b), and 40 CFR 60.5515 to other subparts of part 60. In a separate rulemaking finalized concurrently wit h this rule, the EPA is also finalizing corresponding edits to 40 CFR 60.5705 in Subpart UUUU to clarify that the reg ulated pollutant is the same for both the CAA section 111( b) and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 692 of 854 section 111(d) rules. As of this time, the EPA has not proposed GHG standards for other source categories under CAA section 111. To the extent needed, this approach of adding provi sions to a few subparts in part 60 would be less burdensome to states and more efficient than revising section40 CFR 51.166 at this time solely to address the implications of regulating GH Gs under CAA section 111. The EPA understands that many commenters expressed

concernedconcern that PSD SIPs would also have to be amended to address the implications of regulating GHGs under C AA section 111. However, the language in 60.46Da(j), 60.4315(b), and40 CFR 60.5515 is designed to avoid the need for states to make revisions to the PSD regulations in their SIPs at t his time. The EPA has previously observed that the form of each p ollutant regulated under the PSD program is derived from the form of the pollutant described in regulations, such as an NSPS , that make the pollutant regulated under the CAA. 56 FR 24468, 24470 (May 30, 1991); 61 FR 9905, 9912-18 (Mar. 12, 1996); 75 FR at 31522. Moreover, it is more likely that states would need to consider a SIP revision if the EPA were to revise section40 CFR 51.166 in this rule. Revisions to 51.166 can trigge r requirements for states to revise their PSD program provisions

under section40 CFR 51.166(a)(6).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 693 of 854 Given the process required in states to review thei r SIPs and submit them to the EPA for approval, it is most efficient for all concerned when the EPA is able to consolidate its revisions to 40 CFR 51.166. The EPA, thus, believes it will be less work for states if we issue a comprehensive se t of rules addressing regulation of GHGs under the PSD program after the Supreme Court decision. In comments on the proposed rules, states generally did not express concern that the proposed revisions to part 60 were insufficient to avoid the need for SIP revisions. I n our proposal, we addressed any state with an approved P SD SIP program that applies to GHGs which believed that th is final rule would require the state to revise its SIP so that t he Tailoring Rule thresholds continue to apply. First, the EPA e ncouraged any state that considered such revisions necessary to m ake them as soon as possible. Second, if the state could do so promptly, the EPA said it would assess whether to proceed with a separate rulemaking action to narrow its approval of that st ate’s SIP so as to assure that, for federal purposes, the Tailor ing Rule thresholds will continue to apply as of the effecti ve date of the final NSPS rule. 79 FR 1487. The EPA did not re ceive any comments or other feedback from states requesting t hat the EPA narrow their program to ensure the Tailoring Rule t hresholds continue to apply after promulgating this rule. We do not*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 694 of 854 believe such action will be necessary in any state after the Supreme Court decision and our action in this rule is to adopt the proposed part 60 provisions in this final rule for purposes of ensuring the Step 1 BACT applicability level for GHGs continues to apply on an interim basis.

C. Implications for BACT Determinations under PSD New major stationary sources and major modification s at existing major stationary sources are required by t he CAA to, among other things, obtain a permit under the PSD p rogram before commencing construction. The emission thresholds th at define PSD applicability can be found in 40 CFR parts 51 and 52 as discussed briefly, and the PSD thresholds specific to GHGs are explained in the preceding section of this preamble

. Sources that are subject to PSD must obtain a preconstruction permit that contains emission limit ations based on application of BACT for each regulated NSR pollu tant. The BACT requirement is set forth in section 165(a)(4) of the CAA, and in EPA regulations under 40 CFR parts 51 and 52 . These provisions require that BACT determinations be made on a caseby-case basis. CAA section 169(3) defines BACT as:

“ an emissions limitation (including a visible emissi on standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed major stat ionary source or major modification which the Administrato r, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs ,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 695 of 854 determines is achievable for such facility through application of production processes and available m ethods, systems, and techniques, including fuel cleaning, c lean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant ........” Furthermore, this definition in the CAA specifies t hat “[i]n no event shall application of [BACT] result i n emissions of any pollutants which will exceed the e missions allowed by any applicable standard established purs uant to section 111 or 112 of the Act.” This condition of CAA section 169(3) has historical ly been interpreted to mean that BACT cannot be less string ent than any applicable standard of performance under the NSPS. See, e.g., U.S. EPA, PSD and Title V Permitting Guidance for G reenhouse Gases, p. 20-21EPA-457/B-11-001 (March 2011) (“GHG Permitting Guidance ”).” or “Guidance”) at 20-21. Thus, upon completion of an NSPS, the NSPS establishes a “BACT Floor” for PS D permits that are issued to affected facilities covered by t he NSPS. BACT is a case-by-case review that considers a numb er of factors. These factors include the availability, te chnical feasibility, control effectiveness, and the economi c, environmental and energy impacts of the control opt ion. See GHG Permitting Guidance at 17-46. The fact that a minim um control requirement (i.e., the BACT Floor) is established by the EPA through an applicable NSPS (i.e. the BACT floor) does not bar a permitting agency from justifying a more stringent

standardcontrol level as BACT for a specific PSD permit

.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 696 of 854 In the proposed rule, the EPA discussedIt is import ant to understand how this ruleNSPS may relate to determination ofdetermining BACT for new and existing EGUs that require PSD permits. PSD generally applies to major sources, while this NSPS applies to units that may be within a source. Under this NSPS, an affected facility is a new EGU or a modified or reconstructed EGU. The new source NSPS requirements apply, in gen eral, to any stationary source that adds a new EGU that is an af fected facility under this NSPS. This could, for example, include both aa proposed brand new , (“ greenfield EGU facility”) power plant or an existing facilitypower plant that wantsproposes to add a

new EGU in order(e.g., to add or replaceincrease its generating capacity .). While this latter scenario is considered a “new affected facility” under the NSPS, it may also be consideredis generally viewed under PSD as a “modification” of an existing stationary source under PSD . Thus, the new source NSPS requirements could apply to a modification, as that term is defined under PSD. In addition, this NSPS will apply to some modified orand

reconstructed sourcesunits, as those terms are defined in this

rule and under part 60. It is important to recognize thatConsequently, this NSPS could establish a BACT floor for existing stationary sources that are modifying an e xisting EGU and experience an emissions increase that makes the source*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 697 of 854 subject to PSD review. However, a physical change that triggers the NSPS modification or reconstruction requirement s does not necessarily subject the source to PSD requirements, and vice versa. In general, in order to trigger the NSPS mod ification or reconstruction requirements, a physical change must increase the maximum potential hourly emission rate of the pollutant (to be an NSPS modification) or the fixed capital cost of the change must exceed 50 percent of the fixed capital cost of a comparable entirely new facility (to be an NSPS reconstruction ). See 40 CFR 60.2, 60.14, 60.15. Under the PSD program, however, a physical change (or change in the method of operation) must result in an increase in annual emissions of the pollutant by thea specified emission threshold in order to be subject to PSD re quirements. This emission calculation considers the unit’s past annual emissionemissions and its projected annual emissions. See, e.g., 40 CFR 52.21(a)(2)(iv)(C). In addition, the PSD emi ssions test for a modification allows the existing source to co nsider qualifying emission reductions and increases at the source within a contemporaneous period to “net out” of, or avoid, triggering PSD review. Thus, this NSPS could establish a BACT floor for sources that are modifying an existing EG U and their emissions make them subject to PSDThus, it is impor tant to understand the differences in how the term “modific ation” is used in the NSPS and PSD programs, and that a physi cal change*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 698 of 854 that is a modification under one program may not ne cessarily be a modification under the other program

. In the preamble to the proposed ruleNSPS for new sources , the EPA discussed whether a standard of performance for the new source NSPS, specifically the BSER for solid fuel-f ired EGUs that is based on partial CCS, could become the BACT floor when permitting a modified or reconstructed EGUsEGU or non-EGU

sourcessource . As noted above, BACT is a case-specific review by a permitting agency. In evaluating BACT, the permit ting authority should consider all available control tec hnologies that have the potential for practical application t o the facility or emission unit under evaluation. 582 This See GHG Permitting Guidance at 24. This BACT review must include any technologies that are part of an applicable NSPS fo r the specific type of source and would therefore establi sh the minimum level of stringency for the BACT. Thus, it is possible that partial CCS could be considered in a BACT revi ew as an available control option for a modified or reconstr ucted EGU facility, or for another type of source (e.g., natu ral gas processing plant), but this NSPS is not an applicab le standard to such sources so it would not establish a require ment that

582 U.S. EPA, PSD and Title V Permitting Guidance for G reenhouse Gases, p. 24 (March 2011).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 699 of 854 partial CCS is a minimum level of stringency for th e BACT for

those sources. Some commenters expressed concern that, if the EPA finalizes a BSER for utility boilers and IGCC units that is based on partial CCS, it would establish a BACT Flo or for new EGUs that would be inconsistent with prior BACT det erminations for EGUs in both permits issued by EPA Regions and permits issued by state agencies on which the EPA has commented. Many of these comments were more directed at the developmen t and deployment of CCS (i.e., the commenter did not beli eve CCS should be the basis for BSER) rather than examining whether an NSPS should establish the BACT floor for applicable sources, which is a naturalthe legal consequence of setting an NSPS under

the terms of the CAA. WeConsequently, we respond to these comments in other sections of this preamble that su pport the selection of partial CCS as the basis for the BSER for fossil fuel-fired electric utility steam generating units. With regard to the commenters who stated that a BSE R for EGUs that is based on partial CCS would be inconsis tent with BACT determinations in previous GHG PSD permits, it is important to recognize that a BACT determination is a case-by -case analysis and that technological capabilities and co sts evolve*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 700 of 854 over time. 583 In addition, to date the EPA has not issued a PSD permit with GHG BACT for a source that would be an affected

583 In this regard, the 2011 GHG Permitting Guidance s tates that “although CCS is not in widespread use at this time, EPA generally considers CCS to be an ‘available’ ad d-on pollution control technology for facilities emittin g CO 2 in large amounts and industrial facilities with high-p urity CO 2 streams.” GHG Permitting Guidance at 35. The Guidan ce goes on to note that CCS may not be technically feasible at modified sources (citing possible issues with “spac e for CO 2 capture equipment at an existing facility”), or in other specific circumstances. Id. at 36 (“Logistical hurd les for CCS may include obtaining contracts for offsite lan d acquisition ..., the need for funding..., timing of ava ilable transportation infrastructure, and developing a sit e for secure long term storage. Not every source has the resources to overcome the offsite logistical barriers necessa ry to apply CCS technology to its operations, and smaller sources will likely be more constrained in this regard”). I d. at 42- 3 EPA also noted that CCS may be expensive in indiv idual instances and thus eliminated as a control option f or that reason under step 4 of the BACT analysis, noting fu rther that revenues from EOR may offset other costs. Id. at 42-3. See also UARG v. EPA , 134 S.Ct. 2427, 2448 (2014) (noting that EPA’s GHG Permitting Guidance states that carb on capture is reasonably comparable to more traditiona l, endof-stack BACT technologies, and that petitioners do not dispute that)

. As explained at Section V.I.5 above , in determining that partial CCS is BSER for new fossil fuel steam elect ric plants, the EPA has carefully considered the issue of logistics (including cost estimates for land acquis ition, transportation, and sequestration) and costs genera lly. Nor would new plants face the same types of constraints as modified or reconstructed sources in a BACT determi nation, since a new source has more leeway in choosing where to site. See text at V.G.3. above. Moreover, the GHG P ermitting Guidance considered BACT determinations for all typ es of sources, not just those for which the EPA has deter mined in this rule that partial CCS is the BSER, and the con cerns expressed in the Guidance thus must be considered i n that broader context.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 701 of 854 facility requiring partial CCS under this NSPS (i.e ., a fossil fuel-fired steam generating unit), so one cannot de termine whether the EPA – as a PSD permitting authority – h as been either consistent or inconsistent withby setting a BSER of partial CCS in this NSPS. Although , in the course of a BACT review, some permitting authorities may have determined th at CCS is not technologically feasible or economically ach ievable for a gas-fired EGU, because of the case-by-case nature o f the BACT analysis , it does not automatically follow that the same conclusion is appropriate for a solid fuel-fired EG U. Furthermore, PSD permitting requirements first appl ied to greenhouse gasesGHGs in January 2011 and more information about GHG control technology has been gained in this four -and-a-half year period. Thus, we would expect BACT decisions to evolve as well, such that a GHG BACT review for a coal-fired EGU in 2015 may look very different from a review that was done in 2011. Additionally, if a state wasagency is processing a permit application for a solid fuel-fired EGU and CCS wasdoes not proposedpropose CCS as BACT (or does not even consideredconsider

CCS as a possiblean available control for BACT), the EPA is not necessarily required to comment negatively on the d raft permit, or to otherwise request or require that the state a gency amend the BACT to include CCS. For state agencies that ha ve their own

EPA- approved state implementation plan, the state has p rimacy*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 702 of 854 over their permitting actions and discretion to int erpret their approved rules and to apply the applicable federal and state regulatory requirements that are in place at the ti me for the facility in question. The EPA’s role is to provide oversight to ensure that the state operates their PSD program in accordance with the CAA and applicable rules. Furthermore, ifIf the EPA does not adversely comment on a certain draft permit or BACT determination, it does not necessarily imply EPA en dorsement of the proposed permit or determination. Some commenters also felt that the determination of partial CCS as BSER is inconsistent with the agency’s posit ion on CCS in the EPA’s GHG Permitting Guidance, which they say s upports the notion that additional work is required before CCS can be integrated at full-scale electric utility applicati ons. It is important to recognize that the EPA’s permitting guidancePermitting Guidance is guidance --, so it does not contain any final determination of BACT for any sou rce. Furthermore, we disagree with the commenters’ chara cterization

of the content of the GHG Permitting Guidance. The guidanceGuidance specifically states “[f]or the purposes of a BACT analysis for GHGs, the EPA classifies CCS as an add-on pollution control technology that is “available” fo r facilities emitting CO 2 in large amounts, including fossil fuel-fired powe r plants, and for industrial facilities with high-pur ity CO 2*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 703 of 854 streams ( e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron and steel manufacturing ). For these types of facilities, CCS should be listed in Step 1 of a topdown BACT analysis for GHGs.” GHG Permitting Guidan ce at 32. As discussed elsewhere in the Guidance, technologies t hat should be listed in Step 1 are those that “have the potential for practical application to the emissions unit and reg ulated pollutant under evaluation.” GHG Permitting Guidanc e at 24. The EPA continues to stand by its position on the avail ability of CCS in this context, as expressed in the GHG Permit ting Guidance.

The GHG Permitting Guidance continues on to discuss casespecific factors and potential limitations with app lying CCS, and it acknowledges that CCS may not be ultimately selected as BACT in “certain cases” based on technology feasibi lity and cost. GHG Permitting Guidance at 36, 43. While ackn owledging

these potential challenges when it was issued in March 2011, the Guidance clearly does not rule out the selection of CCS as BACT for any source category and it is forward looking. GHG Permitting Guidance at 43 (“... as a result of ongoin g research and development, ... CCS may become less costly and w arrant greater consideration ... in the future”) Nothing in the guidanceGuidance is inconsistent with agency’sEPA’s present*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 704 of 854 position that CCS is adequately demonstrated for th e types of sources covered by this ruleNSPS , as articulated elsewhere in this preamble. A commenter asserted that the GHG Permitting Guidan ce should be amended because it calls for consideratio n of CCS in BACT determinations even though the proposed NSPS requiredidentified "partial CCS" as BSER for new boiler and IGCC

EGUs. The guidanceGuidance explains that “the purpose of Step 1 of the process is to cast a wide net and identify a ll control options with potential application to the emissions unit under review.” GHG Permitting Guidance at 26. The EPA agrees that the GHG Permitting Guidance only uses the term “CCS” an d does not distinguish “partial CCS” from “full CCS.” But cons idering the purpose of Step 1 of the process, we believe that t he term “CCS”, as it wasis used in the GHG Permitting Guidance, adequately describes the varying levels of CO 2 capture. A BACT review should analyze all available technologies in order to adequately support the BACT determination, and may require evaluation of partial CCS, full CCS, and/or no CO 2 capture. The specific facility type and CO 2 capture conditions will dictate the level(s) of CO 2 capture that are most appropriate to consider as “available” in a BACT review.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 705 of 854 D. Implications for Title V Program

Under the titleTitle V program, certain stationary sources, including “major sources” are required to obtain an operating permit. This permit includes all of the CAA require ments applicable to the source, including adequate monito ring, recordkeeping, and reporting requirements to assure sources’ compliance. These permits are generally issued thro ugh EPAapproved State titlestate Title V programs. In the January 8, 2014 proposal, the EPA discussed whether this rulemaking would impact the applicability of titleTitle V requirements to major sources of GHGs. 79 FR at 1489-90. The relevant issue for titleTitle V purposes was, in essence, whether promulgation of CAA section 111 requirement s for GHGs would undermine the Tailoring Rule, which, as expla ined above, phased in permitting requirements for GHG emissions for stationary sources under the CAA PSD and titleTitle V permitting programs. Based on the EPA’s understanding of the C AA at that time, the proposal discussed this issue in the cont ext of the regulatory and statutory definitions of “major sour ce,” focusing on revisions that had been made in the Tailoring Ru le to the definitions in the titleTitle V regulations of “major source” and “subject to regulation.” 79 FR at 1489-90 (quoting 75 FR 31,583). Under the titleTitle V regulations, as revised by the Tailoring Rule, “major source” is defined to includ e, in*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 706 of 854 relevant part, “a major stationary source ... that di rectly emits, or has the potential to emit, 100 tpy or more of an y air pollutant subject to regulation.” The proposal furt her explained that the GHG threshold that had been established in the Tailoring Rule had been incorporated into the defin ition of “subject to regulation” under 40 CFR 70.2 and 71.2, such that those definitions specify “‘that GHGs are not subje ct to regulation for purposes of defining a major source, unless as of July 1, 2011, the emissions of GHGs are from a sour ce emitting or having the potential to emit 100,000 tpy of GHGs on a CO 2 e basis.’” Id . (quoting 75 FR 31,583). The proposal thus

concluded that the titleTitle V definition of “major source,” as revised by the Tailoring Rule, did not on its face distinguish among types of regulatory triggers for titleTitle V. It further

noted that the titleTitle V program had already been triggered for GHGs, and thus concluded that the promulgation of CAA section 111 requirements would not further impact titleTitle V applicability requirements for major sources of GHG s. 79 FR at 1489-90. As noted elsewhere in this section, after the propo sal for this rulemaking was published, the United States Su preme Court issued its opinion in UARG v EPA , 134 S.Ct. 2427 (June 23, 2014), and in accordance with that decision, the D. C. Circuit subsequently issued an amended judgment in Coalition for*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 707 of 854 Responsible Regulation, Inc. v. Environmental Prote ction Agency , Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir ., April 10, 2015). Those decisions support the same overall con clusion as the EPA discussed in the proposal, though for diffe rent reasons. With respect to titleTitle V, the Supreme Court said in

UARG v EPA that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a m ajor source required to obtain a titleTitle V operating permit. In accordance with that decision, the D.C. Circuit’s a mended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency , vacated the titleTitle V regulations under review in that case to the extent that they require a stationary source to obtain a titleTitle V permit solely because the source emits or has the potentia l to emit GHGs above the applicable major source thresholds. The D.C. Circuit also directed the EPA to consider whether a ny further revisions to its regulations are appropriate in lig ht of UARG v.

EPA , and, if so, to undertake to make such revisions. These court decisions make clear that promulgation of CAA section 111 requirements for GHGs will not result in the EPA imposing a requirement that stationary sources obtain a titleTitle V permit*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 708 of 854 solely because such sources emit or have the potent ial to emit GHGs above the applicable major source thresholds. 584 To be clear, however, unless exempted by the Admini strator through regulation under CAA section 502(a), any so urce, including an area source (a “non-major source”), su bject to an NSPS is required to apply for, and operate pursuant to, a titleTitle V permit that assures compliance with all applicab le CAA requirements for the source, including any GHG- related applicable requirements. This aspect of the titleTitle V program is not affected by UARG v. EPA , as the EPA does not read that decision to affect either the grounds other than th ose described above on which a titleTitle V permit may be required or the applicable requirements that must be addressed in titleTitle V permits. 585 Consistent with the proposal, the EPA has conclude d

584 As explained elsewhere in this notice, the EPA int ends to conduct future rulemaking action to make the approp riate revisions to the operating permit rules to respond to the Supreme Court decision and the D.C. Circuit’s amend ed judgment. To the extent there are any issues related to the p otential interaction between the promulgation of CAA section 111 requirements for GHGs and titleTitle V applicability based on emissions above major source thresholds, the EPA ex pects there would be an opportunity to consider those during th at rulemaking.

585 See Memorandum from Janet G. McCabe, Acting Assist ant Administrator, Office of Air and Radiation, and Cyn thia Giles, Assistant Administrator, Office of Enforcement and Compliance Assurance, to Regional Administrators, Regions 1-10 , Next Steps and Preliminary Views on the Application of Clean A ir Act Permitting Programs to Greenhouse Gases Following t he Supreme*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 709 of 854 that this rule will not affect non-major sources an d there is no need to consider whether to exempt non-major source s. Thus, sources that are subject to the CAA section 111 sta ndards promulgated todayin this rule are required to apply for, and operate pursuant to, a titleTitle V permit that assures compliance with all applicable CAA requirements, in cluding any GHG-related applicable requirements. E. Implications for Title V Fee Requirements for GH Gs 1. Why is the EPA revising Title V fee rules as part o f this action? The January 8, 2014 notice of proposed rulemaking (79 FR 1430)(the “EGU GHG NSPS proposal” or “NSPS proposal ”) proposed the first section 111 standards to regulate GHGs at EGUs. That notice also included proposed revisions to the fee requirements of the 40 CFR part 70 and part 71 operating permit rules under Title V of the CAA to avoid inadvertent consequence s for fees that would be triggered by the promulgation of the first CAA section 111 standard to regulate GHGs. If we do not revise the fee rules by the time of the promulgation of the NS PS standards for GHGs, then approved part 70 programs implemente d by state,

Court’s Decision in Utility Regulatory Group v. Env ironmental Protection Agency (July 24, 2014) at 5.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 710 of 854 local and tribal permitting authorities 586 that rely on the “presumptive minimum” approach and the part 71 prog ram implemented by the EPA would be required to account for GHGs in emissions-based fee calculations at the same dollar per ton ($/ton) rate as other air pollutants. The EPA belie ves this would result in the collection of fees in excess of what is required to cover the reasonable costs of an operat ing permit program. See NSPS proposal at79 FR 1490. In response to these concerns, the EPA proposed re gulatory changes to limit the fees collected based on GHG em issions and proposed two fee adjustment options to increase the fees collected based on the costs for permitting authori ties to conduct certain review activities related to GHG em issions, while still providing sufficient funding for an ope rating permit program. Also, we proposed an option that would hav e provided for no fee adjustments to recover the costs of cond ucting review activities related to GHG emissions. Id

. at79 FR 1490. The EPA did not propose any action related to state and loc al permitting authorities that do not use the presumptive minimum approach. Most commenters on the proposal, including state a nd local permitting authorities, were supportive of exemptin g GHGs from

586 Hereafter, for the sake of simplicity, we will gen erally refer to part 70 permitting authorities as “state” permitting authorities and refer to part 70 programs as “state ” programs.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 711 of 854 the emissions-based fee calculations of the permit rules, but support for the fee adjustment options was mixed, w ith state and local permitting authorities generally supporting e ither of the two fee adjustments, and other commenters generally supporting the option that provides for no fee adjustment. 2. Background on the Fee Requirements of Title V In the NSPS proposal, the EPA explained the statut ory and regulatory background related to the requirement th at permitting authorities collect fees from the owner or operator of titleTitle V sources that are sufficient to cover the costs o f the operating permit program. CAA section 502(b)(3) (A) requires an operating permit program to include a requiremen t that sources “pay an annual fee, or the equivalent over some other period, sufficient to cover all reasonable (direct and indirect) costs required to develop and administer the permit program.” See also 40 CFR 70.9(a). CAA section 502(b)(3)(B)(i ) requires that, in order to have an approvable operating perm it program, the permitting authority must show “the program wil l result in the collection, in the aggregate, from all sources [required to get an operating permit], of an amount not less tha n $25 per ton of each regulated pollutant [adjusted annually for changes in the consumer price index], or such other amount as the Administrator may determine adequately reflects the reasonable costs of the permit program.” See also 40 CFR 70.9( b)(2). This*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 712 of 854 has been generally referred to as the “presumptive minimum” approach. If a permitting authority does not wish t o use the presumptive minimum approach, it may demonstrate “t hat collecting an amount less than the [presumptive min imum amount] will” result in the collection of funds sufficient to cover the costs of the program. CAA section 503(b)(3)(B)(iv); see also 40 CFR 70.9(b)(5). This has been generally referred to as the “detailed accounting” approach. CAA section 502(b)( 3)(B)(ii) sets forth a definition of “regulated pollutant” fo r purposes of calculating the presumptive minimum that includes e ach pollutant regulated under section 111 of the CAA. See also 40 CFR 70.2. 3. What fee rules did we propose to revise? In the NSPS proposal, to exempt GHGs from emissions -based fee calculations, we proposed to exempt GHGs from t he definition of “regulated pollutant” for purposes of operating permit fee calculations (“the GHG exemption”). The EPA then pr oposed two alternative ways to account for the costs of addres sing GHGs in operating permits through a cost adjustment. First, we proposed a modest additional cost for each GHG-related activ ity of certain types that a permitting authority would pro cess (“the GHG adjustment option 1”). Alternatively, we propos ed a modest additional increase in the per ton rate used in the presumptive minimum calculation for all non-GHG fee pollutants (“the GHG adjustment option 2”). The EPA also solicited comme nt on an*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 713 of 854 option that would provide no additional cost adjust ment to account for GHGs (“the GHG adjustment option 3”). A ll of the GHG adjustment options are based on the assumption that the GHG exemption is finalized. See NSPS Proposal at79 FR 1493-1495. The EPA additionally proposed two clarifications. T he first was regulatory text in 40 CFR part 60, subparts Da, KKKK and TTTT, to clarify that GHGs, as opposed to CO 2 , is the regulated pollutant for fee purposes (“the fee pollutant clar ification”).

Id . at 1505, 1506 and 1511. The second was a proposal to move the existing definition of “Greenhouse gases (GHGs) ” within 40 CFR 70.2 and 71.2 to promote clarity in the regulat ions (“the GHG clarification”). Id. at79 FR 1490, 1517, 1518. For background purposes, below is a brief summary o f each of the proposals. a. The GHG exemption

. To address the fee issues discussed in the NSPS pro posal, the EPA proposed to exempt GHG emissions from the d efinition of “regulated pollutant (for presumptive fee calculati on)” in 40 CFR 70.2 and the definition of “regulated pollutant (for fee calculation)” in 40 CFR 71.2. 587 See NSPS preamble at79 FR 1493, 1495.

587 Hereafter we will refer to these definitions as th e “fee pollutant” definitions. Also, note that both fee po llutant definitions cross-reference the definitions of “reg ulated air*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 714 of 854 b. The GHG adjustment option 1

. The first proposed “GHG adjustment” option (option 1) was to include an additional cost for each GHG-related activity of certain types that a permitting authority would pro cess (an activity-based adjustment). The three activities id entified for this option were “GHG completeness determination (f or initial permit or for updated application)” at 43 hours of burden, 588 “GHG evaluation for a modification or related permi t action” at 7 hours of burden, and “GHG evaluation at permit re newal” at 10 hours of burden. See also 79 FR 1494, fn. 280 (prov iding a description of each of these activities). For part 70, the burden hours per activity would be multiplied by the cost of staff time (in $/hour) sp ecific to the state, including wages, benefits, and overhead, to determine the cost of each activity. All the activities for a giv en period would be totaled to determine the total GHG adjustm ent for the state. See 79 FR at 1494. For part 71, we proposed a labor rate assumption of $52 per hour in 2011 dollars. Using that labor rate, we pro posed to determine the GHG fee adjustment for each GHG permi tting program activity to be a specific dollar amount for each ac tivity (“set

pollutant” which includes air pollutants “subject t o any standard promulgated under section 111 of the Act.” 588 Burden is the hours of staff time necessary to per form a task.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 715 of 854 fees”) that the source would pay for each activity performed. See 79 FR at 1495. The EPA proposed to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement th is option. c. The GHG adjustment option 2

. The second proposed GHG adjustment option (option 2 ) was to increase the dollar per ton ($/ton) rates used in t he fee calculations for each non-GHG fee pollutant. The re vised $/ton rates would be multiplied by the total tons of non- GHG fee pollutants actually emitted by any source to determ ine the applicable total fees. The EPA proposed to increase the $/ton rates by 7 percent. 589 See NSPS proposal at79 FR 1494, 1495. d. The GHG adjustment option 3

. The EPA also solicited comment on not charging any fees related to GHGs (option 3). The basis for this prop osed option was the observation that most sources that need to address GHGs in a permit would also emit non-GHG fee pollutants, and thus, the cost of permitting for any particular source ma y be accounted for adequately without charging any addit ional fees

related to GHGs. Id. at79 FR 1494-1495.

589 The EPA estimated that both options 1 and 2 would result in about a 7 percent increase in the fees collected by operating permit programs affected by the proposed rule. For example, the presumptive minimum fee rate in effect for Septembe r 1, 2014 through August 31, 2015 is $48.27/ton. A 7 percent increase under option 2 would result in a revised fee of $51 .65/ton.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 716 of 854 e. The fee pollutant clarification

. Another fee-related proposal was to add regulatory text to 40 CFR part 60, subparts Da, KKKK and TTTT, to clar ify that the fee pollutant for operating permit purposes would b e considered to be “GHGs,” (as defined in 40 CFR 70.2 and 71.2), 590 rather than solely CO 2, which would be regulated under the section 111 standards and implemented through the EGU GHG NSPS. Id

. at79 FR 1505, 1506, and 1511. f. The GHG clarification

. The EPA proposed to move the existing definition of “Greenhouse gases (GHGs)” within the definition of “Subject to regulation” in 40 CFR 70.2 and 71.2 to a separate d efinition within those sections to promote clarity in the reg ulations. Id. at79 FR 1490, 1517, 1518.

4. What action is the EPA finalizing? In this action, the EPA is finalizing the following elements as proposed: (1) the GHG exemption, (2) th e GHG adjustment option 1, and (3) the fee pollutant clar ification. Public commenters on the proposal stated both supp ort and opposition to using the NSPS rulemaking action to r evise the

590 Note that in 40 CFR §70.2 and §71.2, the term “Gre enhouse gases (GHGs)” is defined as the “aggregate group of six g reenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur he xafluoride.”*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 717 of 854 titleTitle V fee rules. Two commenters stated that proposing the titleTitle V fee revisions within the NSPS rulemaking would result in fewer commenters, particularly state and local permitting authorities, having knowledge of the cha nges to the fee rules and sufficient opportunity to comment on the changes because the NSPS proposal is limited to a single so urce category, and one stated that a separate proposal f or the fee rules would provide a sufficient opportunity for pu blic comment. The EPA believes it is appropriate to move forward with final action amending the titleTitle V fee regulations as part of this NSPS. As we explained in the preamble for the propo sal and elsewhere in this final rule, the fee rules and the section 111 standards are interrelated because, if we do not re vise the fee rules, promulgation of the final NSPS will trigger certain requirements related to titleTitle V fees for GHG emissions that the EPA believes will result in the collection of e xcessive fees in states that implement the presumptive minimum ap proach and in the part 71 program. Thus, it is important to final ize the revisions to the fee rules at the same time or prio r to this NSPS, and it is within the EPA’s discretion to addr ess the NSPS and the fee rules at the same time as part of the s ame rulemaking action. In response to the commenters wh o were concerned that including the fee rule proposal as p art of the NSPS proposal would result in the public not having sufficient*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 718 of 854 public comment opportunities, the EPA believes suff icient public comment opportunities were provided on the fee rule changes because the proposal met all public participation r equirements and we provided additional public outreach, includi ng to state and local permitting authorities, which discussed t he fee rule proposal. In addition to the publication of the pro posed rulemaking in the Federal Register, the EPA held nu merous hearings, reached out to state partners and the pub lic, and developed numerous fact sheets and other informatio n to support public comment on this rule. The EPA has complied w ith the applicable public participation requirements and ex ecutive orders. The proposal met all the requirements for p ublic notice – it contained a clear and detailed explanation of how the part 70 and 71 rules would be affected by the promulgati on of the CAA section 111 standard for EGUs and how the EPA propo sed to revise the related regulatory provisions. We received many comments on the proposal to revise the fee rule for operating p ermits programs, and we are taking those comments into con sideration in the finalization of the rulemaking action. a. The GHG exemption .exemption. The EPA is taking final action to revise the defini tion of regulated pollutant (for presumptive fee calculatio n) in 40 CFR 70.2 and regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt GHG emissions. This regulatory amend ment will*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 719 of 854 have the effect of excluding GHG emissions from bei ng subject to the statutory ($/ton) fee rate set for the presumpt ive minimum calculation requirement of part 70 and the fee calc ulation requirements of part 71. We received supportive com ments from the majority of public commenters, including state and local permitting authorities and others, on revising the operating permit rules to exempt GHGs from the emission-based calculations that use the statutory fee rates. We are finalizing this portion of the proposal for the same reasons we explained i n the proposal notice, including that leaving these regul ations unchanged would have resulted in the collection of fee revenue far beyond the reasonable costs of an operating per mit program. The EPA believes that these revisions (in conjuncti on with the GHG adjustment, see below) are consistent with the CAA requirements for fees pursuant to the authority of section 502(b)(3)(B)(i). Some members of the public opposed the proposed GH G exemption for reasons including that it may limit p ermitting authorities’ ability to charge sufficient fees to c over the cost of GHG permitting 591 if the state is barred from exceeding minimum requirements set by the EPA. Despite this a dverse

591 We use the term “GHG permitting” in this section o f the notice to refer to measures undertaken by permittin g authorities to ensure that GHGs and any applicable requirements related to GHGs are appropriately addressed in titleTitle V permitting.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 720 of 854 comment, the EPA believes it is appropriate to fina lize the GHG exemption because we are not finalizing any require ments that would require states to charge any particular fees to any particular sources. The changes we are finalizing t o part 70 concern the presumptive minimum approach, which set s a minimum fee target for states that have decided to follow t he presumptive minimum approach. Neither the statute n or the final rule require any state following the presumptive mi nimum approach (or any other approach) to charge fees to sources using any particular method. Thus, the GHG exemption will not limit states’ ability to structure their individual fee p rograms however they see fit in order to meet the requireme nt that they collect revenue sufficient to cover all reasonable costs of their permitting program. See CAA section 502(b)(3) ; 40 CFR 70.9(b)(3). b. The GHG adjustment option 1

. The EPA is finalizing GHG adjustment option 1 becau se we believe it will result in a system for the calculat ion of costs for part 70 and fees for part 71 that is most direc tly related to the costs of GHG permitting. The EPA has determi ned that some adjustment to cost and fee accounting is important because the recent addition of GHG emissions to the operating p ermitting program does add new burdens for permitting authori ties. Although GHG adjustment option 3 (no GHG permitting fee*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 721 of 854 adjustments) was supported by many industrial comme nters, the EPA rejected it because it is in tension with the s tatutory requirement that permitting authorities collect suf ficient fees to cover all the reasonable costs of permitting. Se e CAA section 502(b)(3)(A). Some state and local permitting autho rities provided comments supporting option 1, while others supported option 2, and some supported either option, stating no preference. Also, a few state and local permitting authorities supported finalizing no adjustment and a few others asked for flexibility to set fee adjustments not proposed by the EPA, but that they believed would be appropriate for their p rogram. The EPA is finalizing option 1 instead of option 2 because the option 1 adjustments are based on the actual co sts for permitting authorities to process specific actions that require GHG reviews. The option 2 approach, which would hav e added a 7 percent surcharge to the $/ton rate used in the fee -related calculations, may have been administratively easier to implement, but is tied to the emissions of non-GHG air pollutants, which are not directly related to the c osts of GHG permitting. permitting. Consistent with CAA section 502(b)(3)(B)(i), the Administrator has determined that the final rule’s approach of exempting GHG emissions from fee-related calculatio ns and accounting for the GHG permitting costs through opt ion 1 will*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 722 of 854 result in fees that will cover the reasonable costs of the permitting programs. The EPA is revising the part 70 regulations throug h this final action, specifically 40 CFR 70.9(b)(2), to mo dify the presumptive minimum approach to add the activity-ba sed cost of GHG permitting activities, outlined in the revised 40 CFR 70.9(b)(2)(v), to the emissions-based calculation o f 40 CFR 70.9(b)(2)(i), which is being revised to now exclud e GHG emissions. To determine the activity-based GHG adju stment under 40 CFR 70.9(b)(2)(v), the permitting authority will multiply the burden hours for each activity (set forth in the re gulation) by the cost of staff time (in $ per hour), including w ages, benefits, and overhead, as determined by the state, for the particular activities undertaken during the particu lar time period. States that implement the presumptive minimum appr oach will need to follow the final rule’s option 1 approach. 592 States that use the detailed accounting approach are not direct ly affected by this rulemaking, but they must ensure that their fee

592 A presumptive minimum state may require various ch anges to its approved operating permit program before it may begin to implement the option 1 approach. For example, its r egulations, and/or program procedures and practices, may need t o be revised, depending on the structure of the fee provisions in the state’s program; thus, the exact response necessary to addr ess this final action may vary from state to state.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 723 of 854 collection programs are sufficient to fully fund al l reasonable costs of the operating permit program, including co sts attributable to GHG-related permitting. The EPA sug gests states that use the detailed accounting approach consider the 7 percent assumption for the costs of GHG permitting in any s uch analysis, consistent with the EPA analysis of options 1 and 2 in the proposal. Consistent with 40 CFR 70.4(i), a state that wishe s to change its operating permit program as a result of this final rule must apprise the EPA. The EPA will review the materials submitted concerning the change and decide if a for mal program revision process is needed and will inform the stat e of next steps. The communication apprising the EPA of any s uch changes should include at least a narrative description of the change and any other information that will assist the EPA in its assessment of the significance of the changes. Cert ain changes, such as switching from the presumptive minimum meth od to a detailed accounting fee demonstration method, will be considered substantial program revisions and be subject to the requirements of 40 CFR 70.4(i)(2). With respect to the part 71 program, in this final action the EPA is revising 40 CFR 71.9(c) to require each part 71 source to pay an annual fee which is the sum of the activitybased fee of 40 CFR 71.9(c)(8) and the emissions-ba sed fee of 40*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 724 of 854 CFR 71.9(c)(1)-(4) 593 , which excludes GHG emissions. To determine the activity-based fee, the revised 40 CFR 71.9(c)( 8) requires the source to pay a “set fee” for each listed activ ity that has been initiated since the fee was last paid. Under p art 71, fees are typically paid at the time of initial applicati on submittal, and thereafter, annually on the anniversary of the initial fee payment, or on any other dates that may be establis hed in the permit. These set fees would not change until such time as we may revise our part 71 rule to change the set fees. The final rule implements the option 1 approach by listing three activities performed by permitting authoritie s that involve GHG reviews. The following describes the ac tivities as described in our proposal and certain clarification s we are making in the final rule to ensure consistent imple mentation. The EPA is finalizing that the first listed activi ty under option 1 is “GHG completeness determination (for in itial permit or updated application).” This activity must be cou nted for each new initial permit application, even for applicatio ns that do not include GHGs emissions or applicable requiremen ts, since an

593 Note that the emissions-based fee calculation diff ers somewhat depending on whether the part 71 program i s being implemented by the EPA [( see 40 CFR §71.9(c)(1 )];)); a state, local or tribal agency with delegated authority fro m the EPA [( see §71.9(c)(2 )];)); the EPA with contractor assistance [( see §71.9(c)(3 )];)); or an agency with partial delegation authority [( see §71.9(c)(4 )].)).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 725 of 854 important part of any completeness determination wi ll be to determine that GHG emissions and applicable require ments have been properly addressed, as needed, in the applicat ion. The fee for this activity is a one-time charge that covers the initial application and any supplements or updates. The EPA believes that a single charge for a GHG completeness determi nation will be adequate to cover the reasonable costs for a per mitting authority to review an initial application and any subsequent application updates related to initial permit issua nce; thus, any updates to an initial application are included in a single “GHG completeness determination,” rather than as a separate activity for which the source would be charged in a ddition to the completeness determination for the initial appl ication. This is an important distinction because many sources su bmit multiple permit application updates, either voluntarily or a s required by the permitting authority, during application review , many of which do not require a separate or comprehensive co mpleteness determination. The EPA is finalizing regulatory text that would d escribe the second listed activity as “GHG evaluation for a permit modification or related permit action.” 594 The EPA had proposed

594 The EPA notes that the term “permit modification” in this context refers to all significant permit modifications and minor*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 726 of 854 that the second listed activity under option 1 woul d be “GHG evaluation for a modification or related permit act ion.” For the final rule, we are clarifying that we are adding a cost for a “permit modification” rather than for a “modificati on.” The term “modification” may be interpreted to refer to any c hange at a source, even a change that would not be required to be processed as a “permit modification,” while “permit modificat ion” refers to any revision to an operating permit that cannot be processed as an administrative permit amendment and thus requ ires a review by a permitting authority as either a significant o r minor permit modification. The EPA is finalizing the third activity as “GHG e valuation at permit renewal.” This activity covers the proces sing of all permit renewal applications and will involve evalua tions of whether any GHG applicable requirements are properl y included. Some members of the public commented that finalizi ng a GHG adjustment would inappropriately increase sources’ financial burdens. The EPA has explained, both in the proposa l notice and elsewhere in this preamble, the importance of the f ee-related

permit modifications under operating permit rules, but not to “administrative permit amendments,” as such amendme nts are not defined as “permit modifications” in the permit rul es. See, e.g., 40 CFR §§70.7(d), (e), and (f).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 727 of 854 revisions to account for the costs associated with GHG-related permitting. The EPA believes that the revisions bei ng finalized will result in modest and reasonable fee increases necessary to cover states' increased costs. 595 To the extent that commenters intended to argue that the adjustments we proposed would exceed the actual costs of GHG permitting, no commenters p rovided any information or analysis to support that position. S ome commenters did state that the costs associated with GHG-related permitting should be minimal because few applicable requirements will apply to GHGs. As stated earlier in this notic e, the EPA’s cost estimate for the proposal concerned the increm ental costs of GHG permitting for any source, not just those th at would have, at the time of the analysis, triggered the re quirement to get a permit based on GHG emissions or applicable r equirements. Despite some comments received to the contrary, th e EPA does not believe it is appropriate to delay the fin alization of the GHG adjustment. The EPA does not believe such d elays would be consistent with CAA section 502(b)(3)(A) because states have been incurring costs attributable to GHG permitting for several years now and increased fees must be collected to c over the increased costs. The regulatory changes being final ized in this

595 The EPA estimated in the proposal that option 1 wo uld result in about a 7 percent overall increase in the annual part 70 fees that are collected by all permitting authorities na tionally. See 79 FR at 1494.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 728 of 854 action provide the states with optimal flexibility and sufficient funding to implement their GHG permittin g programs. Some commenters had specifically stated that the EP A should delay finalization of this rule until the completio n of the next ICR renewal process. While we do not believe delayi ng this rule is appropriate, as explained above, the EPA notes t hat we remain committed to collecting and analyzing additional da ta on costs attributable to GHG permitting for operating permit programs. We may adjust the GHG cost adjustments in future rulem akings if necessary to comply with the requirements of the Ac t. As an alternative to the options proposed by the E PA, some commenters asserted that the EPA should make a GHG cost adjustment using a separate, but reduced fee rate ( $/ton) for GHGs. We, however, believe that the option 1 approa ch of the final rule will be more equitable for sources and m ore representative of actual costs because option 1 con siders the costs of the actual permitting activities performed by a particular permitting authority, while any emission s-based approach would not be as directly related to actual costs incurred by permitting authorities. Some commenters alleged that the EPA’s proposal on adjustments to the operating permit programs was va gue. The EPA provided a thorough discussion of our rationale in the proposal, including the basis for the GHG adjustments, and we proposed*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 729 of 854 regulatory text to implement our proposal. We expla ined in the proposal that support for the cost adjustment for G HGs under option 1 is contained in several analyses performed by the EPA and approved by the OMB related to the effect of th e addressing GHG requirements in operating permits. These analys es have been placed in the docket for this rulemaking. The analy ses include: the Regulatory Impact Assessment (RIA) for the Tail oring Rule (see Regulatory Impact Analysis for the Final Preve ntion of Significant Deterioration and Title V Greenhouse Ga s Tailoring Rule, Final Report, May 2010); the part 70 ICR chan ge request for the Tailoring Rule (which was based on the RIA for the Tailoring Rule); and the current ICR for part 70 (E PA ICR number 1587.12; OMB control number 2060–0243). Several commenters asked that we make changes to t he option 1 approach that we proposed, such as adding new act ivities or decreasing the costs we assumed for the proposal. I n response to these comments, we note that we received no quantit ative data or other information from commenters that we believe d emonstrates the need to revise the list of activities we includ ed under option 1 or the burden hour assumptions under optio n 1 for the activities. Note that to promote consistent impleme ntation of the final option 1 approach, the preamble describes elsewhere a few clarifications concerning the activities under option 1 and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 730 of 854 one minor revision to the regulatory text of one of the activities. Since the EPA’s proposed rulemaking, the Supreme C ourt decided in UARG v. EPA that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a sou rce is a major source required to obtain a titleTitle V operating permit. 596 The EPA’s review of the effect of the Supreme Cour t decision on the burden hour assumptions for the GHG review activities under proposed option 1 is that the effe cts are not significant enough to warrant revision of the burde n hour assumptions in the final rule. Proposed option 1 wa s based on the assumption that permitting authorities would ne ed to evaluate all permit applications for initial permit issuance, significant and minor permit modifications, and per mit renewals for GHG issues (even if there are no applicable GHG requirements). Even after the UARG v. EPA decision, permitting authorities will continue to need to evaluate GHG i ssues for

596 The EPA does not, however, read the UARG decision to affect other grounds on which a titleTitle V permit may be required or the applicable requirements that must be addressed in titleTitle V permits. See Memorandum from Janet G. McCabe, Acting Assistant Administrator, Office of Air and Radiation, and Cyn thia Giles, Assistant Administrator, Office of Enforcement and Compliance Assurance, to Regional Administrators, Regions 1-10 , Next Steps and Preliminary Views on the Application of Clean A ir Act Permitting Programs to Greenhouse Gases Following t he Supreme Court’s Decision in Utility Regulatory Group v. Env ironmental Protection Agency (July 24, 2014) at 5.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 731 of 854 sources applying for a title V permit and for permi t modifications and renewals for existing permits, an d we do not anticipate that the decision will significantly aff ect the total number of such evaluations that will occur in any g iven year compared to the assumptions in our analysis, which as explained above, were based on the incremental costs of GHG p ermitting for any source. Thus, we are finalizing the burden hour assumptions as they were proposed. See NSPS proposal at 1494 an d the supporting statement for the 2012 part 70 ICR renew al. Also, as discussed previously, we remain committed to collec ting and analyzing additional data on costs and we may adjus t the burden hour assumptions or other aspects of option 1 in a future rulemaking, if needed. c. The fee pollutant clarification

. We are also finalizing the proposed addition of tex t within 40 CFR part 60, subpart TTTT, to clarify that the f ee pollutant for operating permit purposes is GHG (as defined in 40 CFR 70.2 and 71.2). We are finalizing these provisions to ad d clarity to our regulations and to avoid the potential need for possible future rulemakings to adjust the title V fee regula tions if any constituent of GHG, other than CO 2 , becomes subject to regulation under section 111 for the first time. The proposal was to add this clarifying text to 40 CFR prtpart 60, subparts Da, KKKK and TTTT. The final rule adds the clarification text on ly to subpart*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 732 of 854 TTTT because the EPA is codifying all of the requir ements for the affected EGUs in a new subpart TTTT and includi ng all GHGCO 2 emission standards for the affected sourcesEGUs (electric utility steam generating units, as well as natural gas-fired stationary combustion turbines) in that newly creat ed subpart. See Section III.B of this preamble for more on this subject. d. The GHG clarification

. The EPA is taking no action at this time on the pro posal to move the definitions of “Greenhouse gases (GHG)” wi thin the definition of “Subject to regulation” in 40 CFR par ts 70 and 71. No public comments were received on this proposed c larification; however, subsequent to the proposal, on June 23, 20 14, the Supreme Court in UARG v. EPA decided that GHG emissions could not be used in making certain applicability determi nations under the operating permit rules. More specifically with respect to title V, as described above, the Supreme Court said that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source requ ired to obtain a title V operating permit. In accordance wi th the Supreme Court decision, on April 10, 2015, the D.C. Circuit issued an amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency , Nos. 09- 1322, 10-073, 10-1092 and 10-1167 (D.C. Cir. April 10, 2015), which, among other things, vacated the title V regu lations under*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 733 of 854 review in that case to the extent that they require a stationary source to obtain a title V permit solely because th e source emits or has the potential to emit GHGs above the a pplicable major source thresholds. The D.C. Circuit also dire cted the EPA to consider whether any further revisions to its re gulations are appropriate in light of UARG v. EPA , and, if so, to undertake to make such revisions. In response to the Supreme Court decision and the D .C. Circuit’s amended judgment, the EPA intends to cond uct future rulemaking action to make the appropriate revisions to the operating permit rules. As part of any such future rulemaking action, the EPA may consider finalizing the proposa l to move the definitions of GHGs within the operating permit rul es. F. Interactions with Other EPA Rules Fossil fuel-fired EGUs are, or potentially will be, impacted by several other recently finalized or pro posed EPA

rules. 597 Many of the rules that impact fossil fuel-fired EGU s apply to existing facilities as well as newly const ructed, modified, or reconstructed facilities. In fact, the rules described below are more applicable to existing EGU s than to

597 We discuss other rulemakings solely for background purposes. The effort to coordinate rulemakings is not a defen se to a violation of the CAA. Sources cannot defer complian ce with existing requirements because of other upcoming reg ulations.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 734 of 854 newly constructed, modified, or reconstructed EGUs. Although those rules will affect EGUs as existing sources, b ecause we expect that there will be few NSPS modifications or reconstructions, we don’t anticipate those rules af fecting EGUs as modified or reconstructed sources. In constructi ng new EGUs, sources can take all applicable requirements of the various rules into consideration. 1. Mercury and Air Toxics Standards (MATS) On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to reduce emissions of toxic air pollutants f rom new and existing coal- and oil-fired EGUs. The MATS rule wi ll reduce emissions of heavy metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel (Ni); and acid gases, inc luding hydrochloric acid (HCl) and hydrofluoric acid (HF). These toxic air pollutants, also known as hazardous air polluta nts or air toxics, are known to cause, or suspected of causing , damage nervous system damage, cancer, and other serious he alth effects. The MATS rule will also reduce SO 2 and fine particle pollution, which will reduce particle concentrations in the ai r and prevent thousands of premature deaths and tens of thousands of heart attacks, bronchitis cases and asthma episodes. New or reconstructed EGUs (i.e., sources that comme nce construction or reconstruction after May 3, 2011) s ubject to the*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 735 of 854 MATS rule are required to comply by April 16, 2012 or upon startup, whichever is later. Existing sources subject to the MATS rule were requ ired to begin meeting the rule’s requirements on April 16, 2015. Controls that will achieve the MATS performance sta ndards are being installed on many units. Certain units, espec ially those that operate infrequently, may be considered not wo rth investing in given today’s electricity market, and are closin g. The final MATS rule provided a foundation on which states and other permitting authorities could rely in granting an ad ditional, fourth year for compliance provided for by the CAA. States report that these fourth year extensions are being granted. In addition, the EPA issued an enforcement policy that provides a clear pathway for reliability-critical units to rec eive an administrative order that includes a compliance sch edule of up to an additional year, if it is needed to ensure el ectricity reliability. 598

598 Following promulgation of the MATS rule, industry, states and environmental organizations challenged many aspects of the EPA's threshold determination that regulation of EGUs is "appropriate and necessary" and the final standards regulating h azardous air pollutants from EGUs. The U.S. Court of Appeals for the D.C. Circuit upheld all aspects of the MATS rule. White Stallion Energy Center v. EPA , 748 F.3d 1222 (D.C. Cir. 2014). The decision was unanimous on all issues except a disse nt was filed because the EPA did not consider cost when determin ing regulation of EGUs is appropriate. In Michigan v. EPA , case no. 14-46, the Supreme Court reversed the D.C. Circuit decision*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 736 of 854 2. Cross-State Air Pollution Rule (CSAPR) The CSAPR requires states to take action to improve air quality by reducing SO 2 and nitrogen oxide ( NO X ) emissions that cross state lines. These pollutants react in the at mosphere to form fine particles and ground-level ozone and are transported long distances, making it difficult for other state s to attain and maintain the NAAQS. The first phase of CSAPR be came effective on January 1, 2015, for SO 2 and annual NO X , and May 1, 2015, for ozone season NO X . The second phase will become effective on January 1, 2017, for SO 2 and annual NO x NO X , and May 1, 2017, for ozone season NO x NO X . Many of the power plants participating in CSAPR have taken actions to reduce hazardous air pollutants for MATS compliance that will also r educe SO 2 and/or NO x NO X . In this way these two rules are complementary. Compliance with one helps facilities comply with th e other. 3. Requirements for Cooling Water Intake Structures at Power Plants (316(b) Rule) On May 19, 2014, the EPA issued a final rule under section 316(b) of the Clean Water Act (33 U.S. Code section 1326(b)) (referred to hereinafter as the 316(b) rule.) The r ule was

upholding the MATS rule finding that EPA erred by n ot considering cost when determining that regulation o f EGUs was "appropriate" pursuant to section 112(n)(1). The Su preme Court considered only the narrow question of cost and did not review the other holdings of the D.C. Circuit, nor did the Supreme Court vacate the MATS rule.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 737 of 854 published on August 15, 2014 (79 FR 48300; August 1 5, 2014), and became effective October 14, 2014. The 316(b) rule establishes new standards to reduce injury and death of fish an d other aquatic life caused by cooling water intake structu res at existing power plants and manufacturing facilities. 599 The 316(b) rule subjects existing power plants and manufacturi ng facilities that withdraw in excess of 2 million gallons per da y (MGD) of cooling water, and use at least 25 percent of that water for cooling purposes, to a national standard designed t o reduce the number of fish destroyed through impingement and en trainment. Existing sources subject to the 316(b) rule are req uired to comply with the impingement requirements as soon as practicable after the entrainment requirements are determined. They must comply with applicable site-specific entrainment re duction controls based on the schedule of requirements esta blished by the permitting authority. Additional information re garding the 316(b) rule for existing sources is included in sectionSection IX.C of the preamble to the CAA section 111(d) emis sion guidelines for existing EGUs that the EPA is finali zing simultaneously with this rule. Although the recentl y issued

599 CWA section 316(b) provides that standards applica ble to point sources under sections 301 and 306 of the Act must require that the location, design, construction and capacit y of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 738 of 854 316(b) rule discussed here applies to existing sour ces, there are also 316(b) technology-based standards for new sources with cooling water intake structures. 4. Disposal of Coal Combustion Residuals from Elect ric Utilities (CCR Rule) On December 19, 2014, the EPA issued the final rule for the disposal of coal combustion residuals from electric utilities. The rule provides a comprehensive set of requiremen ts for the safe disposal of coal combustion residuals (CCRs), commonly known as coal ash, from coal-fired power plants. Th e CCR rule establishes technical requirements for existing and new CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating solid waste. New CCR lan dfills and surface impoundments are required to meet the techn ical criteria before any CCR is placed into the unit. Existing CC R surface impoundments and landfills are subject to implement ation timeframes established in the rule for the individu al technical criteria. For additional information regarding the CCR rule, see sectionSection IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneouslyalong with this rule.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 739 of 854 5. Steam Electric Effluent Limitation Guidelines an d Standards (SE ELG Rule) The EPA is reviewing public comments and working to finalize the proposed SE ELG rule which will impact fossil fuelfired EGUs. In 2013, the EPA proposed the SE ELG ru le (78 FR 34432; June 7, 2013) to strengthen the controls on discharges from certain steam electric power plants by revisin g technologybased effluent limitations guidelines and standards for the steam electric power generating point source catego ry. The proposed regulation, which includes new requirement s for both existing and new generating units, would reduce imp acts to human health and the environment by reducing the amount o f toxic metals and other pollutants currently discharged to surface waters from power plants. The EPA intends to take f inal action on the proposed rule by September 30, 2015. Section IX.C of the preamble to the CAA section 111(d) emission guideli nes for existing EGUs that the EPA is finalizing simultaneo usly with this rule includes additional information regarding the SE ELG

rule. The EPA recognizes the importance of assuring that each of the rules described above can achieve its intended environmental objectives in a commonsense, cost-effective manner, consistent with underlying statutory requirements, and while a ssuring a reliable power system. Executive Order (EO) 13563, “Improving*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 740 of 854 Regulation and Regulatory Review,” issued on Januar y 18, 2011, states that “[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt t o promote... coordination, simplification, and harmonization. Ea ch agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innov ation.” Within the EPA, we are paying careful attention to the interrelatedness and potential impacts on the indus try, reliability and cost that these various rulemakings can have. As discussed in earlier sections of this preamble, the EPA has identified potential alternative compliance pat hways for affected newly constructed, modified, and reconstru cted fossil fuel-fired steam generating units. We are finalizing an emission standard for newly constructed highly efficient fossil fuelfired steam generating units that can be met by cap turing and storing approximately 2016 to 23 percent of the CO 2 produced from the facility or by utilizing other technologies suc h as natural gas co-firing. For a subcategory of steam generatin g units that conduct “large” modifications according to definiti ons in this final rule, we are finalizing an emission standard that is based on a unit-specific emission limitation consistent w ith each modified unit’s best one-year historical performanc e and can be met through a combination of best operating practic es and equipment upgrades. For reconstructed steam generat ing units,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 741 of 854 the EPA is finalizing standards of performance base d on the performance of the most efficient generation techno logy available, which we concluded is the use of the bes t available subcritical steam conditions for small units and th e use of supercritical steam conditions for large units. The standards can also be met through other technology options su ch as natural gas co-firing. In light of these potential alternat ive compliance pathways, we believe that sources will h ave ample opportunity to coordinate their response to this ru le with any obligations that may be applicable to affected EGUs as a result of the MATS, CSAPR, 316(b), SE ELG and CCR rules, a ll of which are or soon will be final rules — and to do so in a manner that will help reduce cost and ensure reliability, while also ensuring that all applicable environmental requirem ents are

met. 600 The EPA is also endeavoring to enable EGUs to compl y with applicable obligations under other power sector rul es as efficiently as possible (e.g., by facilitating thei r ability to coordinate planning and investment decisions with r espect to those rules) and, where possible, implement integra ted

600 It should be noted that regulatory obligations imp osed upon states and sources operate independently under diff erent statutes and sections of statutes; the EPA expects that states and sources will take advantage of available flexib ilities as appropriate, but will comply with all relevant lega l requirements.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 742 of 854 compliance strategies. Section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGU s that the EPA is finalizing simultaneously with this rule des cribes such an example with respect to the SE ELG and CCR rules

. In light of the compliance flexibilities we are off ering in this action, we believe that sources will have ampl e opportunity to use cost-effective regulatory strategies and build on their longstanding, successful records of complying with multiple CAA, CWA, and other environmental requirements, while as suring an adequate, affordable, and reliable supply of electr icity.

XIIXIII . Impacts of this Action As explained in the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissio ns for New, Modified, and Reconstructed Stationary Sources: Ele ctric Utility Generating Units” (EPA-452/R- XX-YYY, June15-005, August 2015) (RIA), available data indicate that, even in the ab sence of the standards of performance for newly constructed EGUs , existing and anticipated economic conditions will lead elect ricity generators to choose new generation technologies th at will meet the standards without installation of additional co ntrols. Therefore, based on the analysis presented in Chapt er 4 of the RIA, the EPA projects that this final rule will res ult in negligible CO 2 emission changes, quantified benefits, and costs*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 743 of 854 on owners and operators of newly constructed EGUs b y 2022. 601 This conclusion is based on the EPA’s own modeling as well as projections by EIA. While the primary conclusion of the analysis presented in the RIA is that the standards for newl y constructed EGUs will result in negligible costs and benefits, the EPA has also performed several illustrative analyses thethat show the potential impacts of the rule if certain key assump tions were to change. This includes an analysis of the impacts un der a range of natural gas prices and the costs and benefits as sociated with building an illustrative coal-fired EGU with CCS. T hese are presented in Chapter 5 of the RIA. As also explained in the RIA for this final rule, t he EPA also expects that few sources will trigger either t he NSPS modification or reconstruction provisions that we a re finalizing todayin this rule . In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and be nefits of the standards for modified and reconstructed sources. A. What are the air impacts? As explained immediately above, the EPA does not an ticipate that this final rule will result in notable CO 2 emission changes by 2022 as a result of the standards of performance for newly constructed EGUs. The owners of newly constructed E GUs will

601 Conditions in the analysis year of 2022 are repres ented by a model year of 2020.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 744 of 854 likely choose technologies, primarily NGCC, which m eet the standards even in the absence of this rule due to e xisting economic conditions as normal business practice. As also explained immediately above, the EPA expect s few modified or reconstructed EGUsEGUs to trigger the N SPS modification or reconstruction provisions in the period of analysis. New steam generating EGUs that choose to comply wit h the final standard of performance by implementing parti al postcombustion CCS are likely to use commercially-avail able aminebased capture systems. Some concern has been raised regarding emissions of amines and amine degradation by-produc ts (e.g., NH 3 ) from the capture process. To reduce the amine emiss ions, MHI introduced the first optimized washing system withi n an absorber column in 1994, and developed a proprietary washing system in 2003. In that system, a proprietary reagent is adde d to the water washing section to capture amine impurities s uch as amine, degraded amine, ammonia, formaldehyde, acetaldehyde , carbonic acids and nitrosamines. 602 MHI has continued to improve this technology for further reduction of amine emissions and established an “advanced amine emission reduction s ystem”.

602 Sharma, S.; Azzi, M.; “A critical review of existi ng strategies for emission control in the monoethanola mine-based carbon capture process and some recommendations for improved strategies”, Fuel , 121, 178 (2014).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 745 of 854 Research performed by MHI at Alabama Power’s Plant Barry indicated that an increasing SO 3 content in the flue gas caused a significant increase of amine emissions. During tes ting, at Plant Barry, MHI applied its proprietary washing sy stem and confirmed that the amine emission were drastically reduced. 603

Others have also studied emissions and control stra tegies and have determined that a conventional multi-stage wat er wash and mist eliminator at the exit of the CO 2 scrubber is effective at removal of gaseous amine and amine degradation prod ucts emissions. 604,605 Additional research continues in this area. B. Endangered Species Act Consistent with the requirements of section 7( a)(2) of the Endangered Species Act (ESA), the EPA has also cons idered the effects of this rule and has reviewed applicable ES A regulations, case law, and guidance to determine wh at, if any, impact there may be to listed endangered or threate ned species

or the designated critical habitat . of such species and whether consultation with the U.S. Fish and Wildlife Servic e (FWS) and/or National Marine Fisheries Service (together, the

603 Kamijo, T.; et al., “SO 3 Impact on Amine Emission and Emission Reduction Technology”, Energy Procedia , Volume 37, 1793 (2013). 604 Sharma, S. (2014). 605 Mertens, J.; et al., “Understanding ethanolamine ( MEA) and ammonia emissions from amine based post combustion carbon capture: Lessons learned from field tests”, Int’l J. of GHG Control , 13, 72 (2013).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 746 of 854 Services) is required by the ESA. Section 7(a)(2) of the ESA requires federal agencies, in consultation with the U.S. Fish and Wildlife Service (FWS) and/or the National Mari ne Fisheries Service,Service(s), to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the conti nued existence of federally listed endangered or threate ned species or result in the destruction or adverse modificatio n of designated critical habitat of such species. 16 U.S .C. 1536(a)(2). Under relevant implementing regulations , ESA section 7(a)(2) applies only to actions where there is disc retionary federal involvement or control. 50 CFR 402.03. Furt her, under the regulations consultation is required only for a ctions that “may affect” listed species or designated critical habitat. 50 CFR 402.14. Consultation is not required where the action has no effect on such species or habitat. Under this stand ard, it is the federal agency taking the action that evaluates the action and determines whether consultation is required. See 51 FR 19926, 19949 (June 3, 1986). Effects of an action i nclude both the direct and indirect effects that will be added to the environmental baseline. 50 CFR 402.02. Direct effects are the direct or immediate effects of an action on a liste d species or*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 747 of 854 its habitat. 606 Indirect effects are those that are “ caused by

the proposed action , and are later in time, andbut still are reasonably certain to occur ..” Id. To trigger athe consultation requirement, there must thus be a causal connection between the federal action, the effect in question, and the lis ted species,

and if the effect is indirect, it must be reasonably certain to

occur. The EPA has considered the effects of this rul e and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to list ed species or designated critical habitat for purposes of ESA sec tion 7(a)(2) consultation. The EPA notes that the projected environmental effects of this final action are positive: reductio ns in overall GHG emissions, and reductions in PM and ozone-precu rsor emissions (SO X and NO X ). TheseThe EPA recognizes that beneficial effects to listed species can, as a general matter, result in a “may affect” determination under the ESA. However, the EPA’s assessment that the rule will have an overall net p ositive environmental effect by virtue of reducing emission s of certain air pollutants does not address whether the rule ma y affect any

606 See Endangered Species Consultation Handbook, U.S. Fis h & Wildlife Service and National Marine Fisheries Serv ice at 4- 25(March 1998) (providing examples of direct effect s: e.g. , driving an off road vehicle through the nesting hab itat of a listed species of bird and destroying a ground nest ; building a housing unit and destroying the habitat of a listed species).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 748 of 854 listed species or designated critical habitat for E SA section 7(a)(2) purposes and does not constitute any findin g of effects for that purpose. The fact that the rule will have overall positive effects on the national and global environ ment does not mean that the rule may affect any listed species in its habitat or the designated critical habitat of such species within the meaning of ESA section 7(a)(2) or the implementing regulations or require ESA consultation. The EPA notes that the emission reductions achieved by the

rule are projected to be minor. See Section XIII.F and G. below, and RIA chapter 4. Although the final rule imposes substantial

controls on CO 2 emissions, we project few if any new fossil fuelfired steam generating units to be built. Emissions reductions from turbines are likewise projected to be minimal. Moreover, we reasonably project that capacity additions during t he analysis period out to 2022 would already be compliant with the rule’s requirements (e.g., natural gas combined cycle unit s, low capacity factor natural gas combustion turbines, an d small amounts of coal-fired units with CCS supported by f ederal and state funding). See RIA chapter 4. With respect to the projected GHG emission reductio ns, the EPA does not believe that such minor reductions trigger ESA consultation requirements under section 7(a)(2). In reaching this conclusion, the EPA is mindful of significant legal and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 749 of 854 technical analysis undertaken by FWS and the U.S. D epartment of the Interior (DOI) in the context of listing the polar bear as a threatened species under the ESA. In that context, in 2008, FWS and DOI expressed the view that the best scientific data available were insufficient to draw a causal connec tion between GHG emissions and effects on the species in its hab itat

. 329

. 607 The DOI Solicitor concluded that where the effect a t issue is climate change, proposed actions involving GHG emis sions cannot pass the “may affect” test of the section 7 regulat ions and thus are not subject to ESA consultation. The EPA has also previously considered issues relat ing to GHG emissions in connection with the requirements o f ESA section 7(a)(2 ).) and has supplemented DOI’s analysis with additi onal consideration of GHG modeling tools and data regard ing listed species. The EPA evaluated this same issue in the context o f the light duty vehicle GHG emission standards for model years 2012- 2016 and 2017-2025. There the agency projected GHG emission reductions many orders of magnitude greater over th e lifetimes of the model years in question 330 608 and, based on air quality

607 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from David Longly Bernhardt, Solicitor, U.S. Department of the Interior re: ‘‘Guidance on the Applicability of the Endangered Species Act’s Consultation Requirements to Proposed Actions Involving the Emission of Greenhouse Gases’’ (Oct. 3, 2008). 608 See 75 FR at 25438 Table I.C 2–4 (May 7, 2010); 77 FR at 62894 Table III–68 (Oct. 15, 2012).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 750 of 854 modeling of potential environmental effects, conclu ded that “EPA knows of no modeling tool which can link these smal l, timeattenuated changes in global metrics to particular effects on listed species in particular areas. Extrapolating f rom global metric to local effect with such small numbers, and accounting for further links in a causative chain, remain beyo nd current modeling capabilities.” EPA, Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel Economy Standa rds, Response to Comment Document for Joint Rulemaking at 4-102 ( Docket EPAOAR-HQ-2009-4782). The EPA reached this conclusion after evaluating issues relating to potential improvement s relevant to both temperature and oceanographic pH outputs. The EPA's ultimate finding was that “any potential for a spec ific impact on listed species in their habitats associated with these very small changes in average global temperature and oce an pH is too remote to trigger the threshold for ESA section 7 ( a)(2).” Id. The EPA believes that the same conclusions apply to the present action, given that the projected CO 2 CO 2 emission reductions are

far less than those projected for either of the light d uty vehicle rules. See, e.g., Ground Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a specie s from a federal action is extremely remote, ESA does not re quire consultation). The EPA’s conclusion is entirely consistent with*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 751 of 854 DOI’s analysis regarding ESA requirements in the co ntext of federal actions involving GHG emissions. 609 The EPA received a comment on the proposal referenc ing a prior letter sent to the EPA by three U.S. Senators , 610 which asserted that the rule will cause a shift to altern ative sources of energy such as wind and solar and that such faci lities may have impacts on listed species. The comment inquire d regarding ESA consultation in connection with the rule. We re iterate that no consultation is required for a rule without pote ntial for a specific impact on listed species in their habitats

. C. What are the energy impacts? This final rule is not anticipated to have a notabl e effect on the supply, distribution, or use of energy. As p reviously stated, the EPA believes that electric power compan ies will

609 The EPA has received correspondence from Members o f Congress asserting that the Services have identified several listed species affected by global climate change. The EPA’ s assessment of ESA requirements in connection with the present rule does not address whether global climate change may, as a gen eral matter, be a relevant consideration in the status of certai n listed species. Rather, the requirements of ESA section 7( a)(2) must be considered and applied to the specific action at is sue. As explained above, the EPA’s conclusion that ESA sect ion 7(a)(2) consultation is not required here is premised on th e specific facts and circumstances of the present rule and is fully consistent with prior relevant analyses conducted b y DOI, FWS, and the EPA. 610 See Letter from David Vitter, James M. Inhofe, and Mik e Crapo, United States Senate Committee on Environmen t and Public Works, to Gina McCarthy, Administrator, U.S. Enviro nmental Protection Agency, and Dan Ashe, Director, U.S. Fis h and Wildlife Service, dated March 6, 2014.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 752 of 854 choose to build new EGUs that comply with the regul atory requirements of this rule even in its absence, prim arily NGCC units, because of existing and expected market cond itions. As also previously stated, the EPA expects few reconstructed or modified EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. D. What are the water and solid waste impacts? This final rule is not anticipated to have notable impacts on water or solid waste. As we have noted, the EPA believes that utilities and project developers will choose to bui ld new EGUs that comply with the regulatory requirements of thi s rule even in its absence, primarily through the construction of new NGCC units. As also previously stated, the EPA expects f ew reconstructed or modified EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Still there are expected to be a small number of coal pla nts with CCS and the use of CCS systems (especially post-combust ion system) will increase the amount of water used at the facil ity. If those plantplants utilize partial CCS to meet the final standard of performance (i.e., approximately 2016 to 23 percent capture), the increased water use will not be significant. See Section*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 753 of 854 V.O.2. The EPA is unaware of any solid waste impact result ing from this rule. 611 E. What are the compliance costs? TheFor steam generating EGUs, the EPA has carefully analyzed the costs of meeting the promulgated stand ard of performance for a highly efficient SCPC using parti al CCS and found these costs to be reasonable. See Sections V. H and I above. This analysis assumes new capacity not other wise compliant with the standards would be constructed. Based on the analysis in chapter 4 of the RIA, the EPA believes the standards of performance for newly constructed EGUs will have no notable compliance costs, because electric power companies are expected to build new EGUs that comply with the regulatory r equirements of this final rule even in the absence of the rule, primarily NGCC units, due to existing and expected market con ditions. While the EPA’s analysis and projections from EIA c ontinue to show that the rule is likely to result in negligibl e costs and benefits due to existing generation choices, the EP A recognizes that some companies may choose to construct coal or other fossil fuel-fired units and has set standards for these un its

611 Estimated costs for the rule include costs for fly ash and bottom ash disposal and for spent solvent recovery and handling. See “Cost and Performance Baseline for Fossil Energ y Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3”, DOE/NETL-2015/1723 (July 2015) at pp. 43, 130.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 754 of 854 accordingly. For this reason, the RIA also analyzes projectlevel costs of a unit with and without CCS, to quan tify the potential cost for a fossil fuel-fired unit with CC S. In addition, the EPA believes the standards of perf ormance for modified and reconstructed EGUs will have minim al associated compliance costs, because, as previously stated, th e EPA expects few modified or reconstructed EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. F. What are the economic and employment impacts? The EPA does not anticipate that this final rule w ill result in notable CO 2 emission changes, energy impacts, monetized benefits, costs, or economic impacts by 2022 as a r esult of the standards of performance for newly constructed EGUs . The owners of newly constructed EGUs will likely choose techno logies that meet the standards even in the absence of this rule , due to existing economic conditions as normal business pra ctice. Likewise, the EPA believes this rule will not have any impacts on the price of electricity, employment or labor ma rkets, or the U.S. economy. See RIA chapter 4.6. 612

612 The employment analysis in the RIA is part of the EPA’s ongoing effort to “conduct continuing evaluations o f potential loss or shifts of employment which may result from the administration or enforcement of [the Act]” pursuan t to CAA section 321(a).*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 755 of 854 As previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstruction provisions. As with the new source standards, the EPA does not exp ect macroeconomic or employment impacts as a result of the

standards. G. What are the benefits of the final standards?

ThereWe are nonot projecting direct monetized climate benefits in terms of CO 2 emission reductions associated with these standards of performance. However, by clarifyingThis is because, as stated above, the EPA believes that in the future, newly constructed coal-firedelectric power plantscompanies will be requiredchoose to meetbuild new EGUs that comply with the regulatory requirements of this rule even in its ab sence, primarily NGCC units, because of existing and expec ted market conditions. See RIA chapter 4. Moreover, a particular performancecost-reasonable standard , this rule provides is, in fact, what will drive new technology deployment and provide a path forward for new coal-fired generation and the deployment of CCS. It ensures that new EGUs, whether gas or coal- fired, will

meet standards for CO 2 control into the futurecapacity. See Section V.L above

. As also previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstruction provisions. In Chapter 6 of the RIA, we discuss factors that li mit our*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 756 of 854 ability to quantify the costs and benefits of the s tandards for modified and reconstructed sources.

XIIXIV . Statutory and Executive Order Reviews Additional information about these Statutory and Ex ecutiveOrders can be found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. A. Executive Order 12866 ,: Regulatory Planning and Review , and Executive Order 13563 ,: Improving Regulation and Regulatory Review This final action is a significant regulatory acti on that was submitted to the Office of Management and Budge t (OMB) for review. It is a significant regulatory action becau se it raises novel legal or policy issues arising out of legal m andates. Any changes made in response to OMB recommendations hav e been documented in the established dockets for this acti on under Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Pe rformance for Greenhouse Gas Emissions from New Stationary Source s: Electric Utility Generating Units) and Docket ID No. EPA-HQ- OAR-2013-0603 (Carbon Pollution Standards for Modified and Recons tructed Stationary Sources: Electric Utility Generating Uni ts). The EPA prepared an economic analysis of the potential cost s and benefits associated with this action. This analysis , which is contained in the “Regulatory Impact Analysis for th e Standards of Performance for Greenhouse Gas Emissions for New , Modified,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 757 of 854 and Reconstructed Stationary Sources: Electric Util ity Generating Units” (EPA-452/R- XX-YYY, June15-005, August 2015), is available in both dockets. The EPA does not anticipate that this final ac tion will result in any notable compliance costs. Specificall y, we believe that the standards for newly constructed fossil fue l-fired EGUs (electric utility steam generating units and natura l gas-fired stationary combustion turbines) will have negligibl e costs associated with it over a range of likely sensitivi ty conditions because electric power companies will choose to bui ld new EGUs that comply with the regulatory requirements of thi s action even in the absence of the action, because of existing a nd expected market conditions. (See the RIA for further discuss ion of sensitivities). The EPA does not project any new co al-fired steam generating units without CCS to be built in t he absence of this action. However, because some companies may ch oose to construct coal or other fossil fuel-fired EGUs, the RIA also analyzes project-level costs of a unit with and wit hout CCS, to quantify the potential cost for a fossil fuel-fired EGU with

CCS. The EPA also believes that the standards for modifi ed and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because, as previously stated, th e EPA expects few modified or reconstructed EGUs to trigger the NSPS*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 758 of 854 modification or reconstruction provisions in the period of analysis (through 2022). In Chapter 6 of the RIA, w e discuss factors that limit our ability to quantify the cost s and benefits of the standards for modified and reconstr ucted

sources. B. Paperwork Reduction Act (PRA) The information collection activities in this final action

have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number XX2465.03 . Separate ICR documents were prepared and submitted to OMB fo r the proposed standards for newly constructed EGUs (EPA ICR number 2465.02) and the proposed standards for modified an d reconstructed EGUs (EPA ICR number 2506. 0301 ). Because the CO 2 standards for newly constructed, modified, and reco nstructed EGUs will be included in the same new subpart (40 C FR part 60, subpart TTTT) and are being finalized in the same a ction, the ICR document for this action includes estimates of the information collection burden on owners and operato rs of newly constructed, modified, and reconstructed EGUs. Esti mated cost burden is based on 2013 Bureau of Labor Statistics (BLS) labor cost data. Thus, all burden estimates are in 2013 d ollars. Burden is defined at 5 CFR 1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbe rs EPA-HQ-*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 759 of 854 OAR-2013-0495 and EPA-HQ-OAR-2013-0603), and it is briefly summarized here. The information collection require ments are not enforceable until OMB approves them. The recordkeeping and reporting requirements in th is final action are specifically authorized by CAA section 1 14 (42 U.S.C. 7414). All information submitted to the EPA pursuan t to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agencyagency policies set forth in 40 CFR part 2, subpart B. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are lis ted in 40 CFR part 9. When OMB approves this ICR, the Agencyagency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection acti vities contained in this final action. 1. Newly Constructed EGUs This final action will impose minimal new informati on collection burden on owners and operators of affect ed newly constructed fossil fuel-fired EGUs (steam generatin g units and natural gas-fired stationary combustion turbines) beyond what those sources would already be subject to under the authorities*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 760 of 854 of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in th e existing part 75 and 98 regulations (40 CFR part 75 and 40 C FR part 98) under the provisions of the Paperwork Reduction Act , 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2 060-0626 and 2060-0629, respectively. Apart from certain reporti ng costs based on requirements in the NSPS General Provision s (40 CFR part 60, subpart A), which are mandatory for all owners/operators subject to CAA section 111 nationa l emission standardsto comply with the emission standards unde r the rule , there are no new information collection costs, as t he information required by the standards for newly con structed EGUs is already collected and reported by other regulato ry programs. The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory r equirements of the rule because of existing and expected market conditions. The EPA does not project any newly constructed coal -fired steam generating units that commenced construction after proposal (January 8, 2014) to commence operation over the 3- year period covered by this ICR. We estimate that 1712 affected newly constructed NGCC units and 25 affected newly constructed natural gas-fired stationarysimple cycle combustion turbines will commence operation during that time period. As a re sult of this final action, owners or operators of those newly co nstructed*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 761 of 854 units will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months. 2. Modified and Reconstructed EGUs This final action is not expected to impose an info rmation collection burden under the provisions of the PRA o n owners and operators of affected modified and reconstructed fo ssil fuelfired EGUs (steam generating units and natural gas-fired stationary combustion turbines). As previously stat ed, the EPA expects few modified or reconstructed EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Specifically, the EPA believes it unlikel y that fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines will take actions t hat would constitute modifications or reconstructions a s defined under the EPA’s NSPS regulations. Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose any information collection burden over the 3-year p eriod covered by this ICR. We have estimated, however, the inform ation collection burden that would be imposed on an affec ted EGU if it was modified or reconstructed. Although not anticipated, if an EGU were to modify or reconstruct, this final action would impose minimal information collection burden on those affected sourcesEGUs beyond what they would already be subject to under the authorities o f CAA 40 CFR*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 762 of 854 parts 75 and 98. As described above, the OMB has pr eviously approved the information collection requirements co ntained in the existing part 75 and 98 regulations. Apart from certain reporting costs , which are mandatory for all owners/operators subject to CAA section 111 nationalcomply with the emission

standards under the rule , there would be no new information collection costs, as the information required by th e final rule is already collected and reported by other regulato ry programs. As stated above, although the EPA expects few sourc es will trigger either the NSPS modification or reconstruct ion provisions, if an EGU were to modify or reconstruct during the 3-year period covered by this ICR, the owner or ope rator of the EGU will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months . The annual reporting burden for such a unit is estimated to be $ 2,6651,333

and 3216 labor hours. There are no annualized capital costs or O&M costs associated with burden for modified or re constructed

EGUs. 3. Information Collection Burden The annual information collection burden for newly constructed, modified, and reconstructed EGUs consi sts only of reporting burden as explained above. The annual rep orting burden for this collection (averaged over the first 3 year s after the effective date of the standards) is estimated to be*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 763 of 854 $ 32,88660,977 and 395651 labor hours. There are no annualized capital costs or O&M costs associated with burden f or newly

constructed , modified, or reconstructed EGUs. Average burden hours per response are estimated to be 87 hours. The total number of respondents over the 3-year ICR period is estimated to

be 3762

. C. Regulatory Flexibility Act (RFA) I certify that this final action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determinatio n, the impact of concern is any significant adverse economic impa ct on small entities. An agency may certify that a rule will no t have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, ha s no net burden or otherwise has a positive economic effect on the small entities subject to the rule. 1. Newly Constructed EGUs The EPA believes that electric power companies wil l choose to build new fossil fuel-fired electric utility ste am generating units or natural gas-fired stationary combustion tu rbines that comply with the regulatory requirements of the fina l rule because of existing and expected market conditions. RIA Chapter

4. The EPA does not project any new coal-fired steam g enerating units without CCS to be built. We expect that any n ewly*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 764 of 854 constructed natural gas-fired stationary combustion turbines will meet the standards. We do not include an analy sis of the illustrative impacts on small entities that may res ult from implementation of the final rule because we anticip ate negligible compliance costs over a range of likely sensitivity conditions as a result of the standards for newly c onstructed EGUs. Thus the cost-to-sales ratios for any affecte d small entity would be zero costs as compared to annual sa les revenue for the entity. Accordingly, there are no anticipat ed economic impacts as a result of the standards for newly cons tructed EGUs. (See the “Regulatory Impact Analysis for the Standa rds of Performance for Greenhouse Gas Emissions for New, M odified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R- XX-YYY, June15-005, August 2015) for further discussion of sensitivities.) We have therefore concluded that this final action will have no net regulatory burde n for all directly regulated small entities. 2. Modified and Reconstructed EGUs The EPA expects few modified fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbinesto trigger the NSPS modification provisions in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the s ource’s maximum achievable hourly rate of emissions. The EP A does not*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 765 of 854 believe that there are likely to be EGUs that will take actions that would constitute modifications as defined unde r the EPA’s NSPS regulations. In addition, the EPA expects few reconstructed foss il fuelfired electric utility steam generating units or na tural gasfired stationary combustion turbines in the period of analysis. Reconstruction occurs when a single project replace s components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to co nstruct a comparable entirely new facility. In Chapter 6 of the RIA, we discuss factors that li mit our ability to quantify the costs and benefits of the s tandards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant c osts on those sources, including any that are owned by small enti ties. (See the “Regulatory Impact Analysis for the Standards o f Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R- XX-YYY, June15-005, August 2015). D. Unfunded Mandates Reform Act (UMRA) This final action does not contain an unfunded mand ate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small governments. The EPA believes the final rule will have negligibl e*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 766 of 854 compliance costs on owners and operators of newly c onstructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new f ossil fuelfired electric utility steam generating units or na tural gasfired stationary combustion turbines that comply wi th the regulatory requirements of the rule because of exis ting and expected market conditions. The EPA does not projec t any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fire d stationary combustion turbines will meet the standards. (See t he “Regulatory Impact Analysis for the Standards of Pe rformance for Greenhouse Gas Emissions for New, Modified, and Rec onstructed Stationary Sources: Electric Utility Generating Uni ts” (EPA452/R- XX-YYY, June15-005, August 2015) for further discussion of sensitivities.) As previously stated, the EPA expects few modified or

reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary co mbustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. In Chapter 6 of the RIA, we discuss factors that limit our ability to quanti fy the costs and benefits of the standards for modified and reco nstructed sources. However, we do not anticipate that the rul e would impose significant costs on those sources. (See the “Regulatory*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 767 of 854 Impact Analysis for the Standards of Performance fo r Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-45 2/R- XX-YYY, June15-005, August 2015).)

We have therefore concluded that the standards for newly constructed, modified, and reconstructed EGUs do no t impose enforceable duties on any state, local or tribal go vernments, or the private sector, that may result in expenditures by state, local and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. We have also concluded that this action does not have regul atory requirements that might significantly or uniquely a ffect small governments. The threshold amount established for d etermining whether regulatory requirements could significantly affect small governments is $100 million annually and, as stated above, we have concluded that the final action will not resul t in expenditures of $100 million or more in any one yea r. Specifically, the EPA does not project any new coal -fired steam generating units without CCS to be built and expect s that any newly constructed natural gas-fired stationary comb ustion turbines will meet the standards. Further, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired station ary*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 768 of 854 combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. E. Executive Order 13132 ,: Federalism This final action does not have federalism implicat ions. It will not have substantial direct effects on the sta tes, on the relationship between the national government and th e states, or on the distribution of power and responsibilities a mong the various levels of government. The EPA believes that electric power companies will choose to build new fossil fue l-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously state d, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. We, therefore, anticipate that the final rule will impo se minimal compliance costs. F. Executive Order 13175 ,: Consultation and Coordination with Indian Tribal Governments This final action does not have tribal implications as specified in Executive Order 13175. The final rule will impose requirements on owners and operators of newly const ructed,*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 769 of 854 modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam generating units, as well as one facility with natural gas-fired stationary comb ustion turbines, located in Indian Country, but is not awa re of any EGUs owned or operated by tribal entities. We note that because

the rule addresses CO 2 emissions from newly constructed, modified, and reconstructed EGUs, it will affect ex isting EGUs such as those located at the four facilities in Ind ian Country only if those EGUs were to take actions constitutin g modifications or reconstructions as defined under t he EPA’s NSPS regulations. As previously stated, the EPA expects few modified

or reconstructed EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Thus, the rule will neither impose substantial direct complia nce costs on tribal governments nor preempt Tribal law. Accordin gly, Executive Order 13175 does not apply to this action

. Nevertheless, because the EPA is aware of Tribal in terest in carbon pollution standards for the power sector and, consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered consultation wi th tribal officials during development of this rule. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consu ltation letters to the leaders of all federally recognized tribes. Although only newly constructed, modified, and reco nstructed*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 770 of 854 EGUs will be affected by this action, the EPA’s con sultation regarded planned actions for new and existing sourc es. The letters provided information regarding the EPA’s de velopment of NSPS and emission guidelines for EGUs and offered c onsultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech L ake Band of Ojibwe. A description of that consultation is inclu ded in the preamble to the proposed standards for new EGUs (79 FR 1501, January 8, 2014). The EPA also offered consultation to the leaders of all federally recognized tribes after the proposed acti on for newly constructed EGUs was signed on September, 20, 2013. On November 1, 2013, the EPA sent letters to tribal leaders tha t provided information regarding the EPA’s development of carb on pollution standards for new, modified, reconstructed and exis ting EGUs and offered consultation. No tribes requested consultat ion regarding the standards for newly constructed EGUs. In addition to offering consultation, the EPA also conducted outreach to tribes during development of this rule. The EPA held a series of listening sessions prior t o proposal of GHG standards for newly constructed EGUs. Tribes pa rticipated in a session on February 17, 2011, with the state agen cies, as well as in a separate session with tribes on April 20, 2 011. The EPA*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 771 of 854 also held a series of listening sessions prior to p roposal of GHG standards for modified and reconstructed EGUs a nd GHG emission guidelines for existing EGUs. Tribes parti cipated in a session on September 9, 2013, together with the sta te agencies, as well as in a separate tribe-only session on Sept ember 26, 2013. In addition, an outreach meeting was held on September 9, 2013, with tribal representatives from some of the federally recognized tribes. The EPA also met with tribal env ironmental staff with the National Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outrea ch is included in the preamble to the proposed emission g uidelines for existing EGUs (79 FR 34830, June 18, 2014). G. Executive Order 13045 ,: Protection of Children from Environmental Health Risks and Safety Risks This action is not subject to Executive Order 13045 because it is not economically significant as defined in Ex ecutive Order 12866. While the action is not subject to Executive Order 13045, the EPA believes that the environmental health or s afety risk addressed by this action has a disproportionate eff ect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children.

CO 2 is a potent greenhouse gasGHG that contributes to*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 772 of 854 climate change and is emitted in significant quanti ties by fossil fuel-fired power plants. The EPA believes that the CO 2 emission reductions resulting from implementation o f these final guidelines, as well as substantial ozone and PM 2.5 emission reductions as a co-benefit, will further improve ch ildren’s health.As stated above, the EPA believes the final rule will have negligible effects on owners and operators of newly constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to bui ld new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that compl y with the regulatory requirements of the rule because of exis ting and expected market conditions. However, the RIA also a nalyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired unit wit h CCS. RIA chapter 5. Under these scenarios, the rule would re sult in substantial reductions of both CO 2 , and also fine particulate matter (sulfate PM 2.5) such that net quantifiable benefits exceed regulatory costs under a range of assumption s. Under these same scenarios, this rule would have a positi ve effect for children’s health. The assessment literature cited in the EPA’s 2009 Endangerment Finding concluded that certain populat ions and lifestages, including children, the elderly, and th e poor, are*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 773 of 854 most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups’ vulnerabilities and the projected impacts they may experience. These assessments describe how children’s unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Imp acts to children are expected from heat waves, air pollutio n, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic disea ses, as well as health effects associated with heat waves, storm s, and floods. Additional health concerns may arise in low income households, especially those with children, if clim ate change reduces food availability and increases prices, lea ding to food insecurity within households. More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of this preamble. H. Executive Order 13211 ,: Actions Concerning Regulations

Thatthat Significantly Affect Energy Supply, Distribution, or

Use This final action is not a “significant energy acti on” because it is not likely to have a significant adve rse effect on*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 774 of 854 the supply, distribution, or use of energy. See Section V.O.3

above. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric util ity steam generating units or natural gas-fired stationary co mbustion turbines that comply with the regulatory requiremen ts of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified

or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary co mbustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. Thus, this action is not anticipated to have notable impacts on emissions, c osts or energy supply decisions for the affected electric u tility industry. I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR part 51 This final action involves technical standards. The followingEPA has decided to use 10 voluntary consensus standards are used(VCS) in the final rule :. One VCS, American National Standards Institute (ANS I) Standard C12.20, “American National Standard for El ectricity Meters - 0.2 and 0.5 Accuracy Classes,” is cited in the final rule to assure consistent monitoring of electric ou tput. This standard is available at http://www.ansi.org or by mail at*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 775 of 854 American National Standards Institute (ANSI), 25 W. 43rd Street, 4th Floor, New York, NY, 10036. Six VCS, American Society for Testing and Materials (ASTM) Methods D388- 12 (99, “ Standard Classification of Coals by

Rank ),”; D396- 13c (98, “ Standard Specification for Fuel Oils ),”; D975- 14 (08a, “ Standard Specification for Diesel Fuel Oils ),”; D3699- 13b (08, “ Standard Specification for Kerosene ),”; D6751- 12 (11b, “ Standard Specification for Biodiesel Fuel Blend Sto ck (B100) for Middle Distillate Fuels ),”; and D7467- 13 (10,

“ Standard Specification for Diesel Fuel Oil, Biodies el Blend (B6 to B20 )), and American National Standards Institute (ANSI ) Standard C12.20 (American National Standard for Ele ctricity Meters - 0.2 and 0.5 Accuracy Classes).)” are cited in the final rule to identify the different fuel types. These st andards are available at http://www.astm.org or by mail at ASTM International, 100 Barr Harbor Drive, P.O. Box CB70 0, West Conshohocken, PA 19428-2959. Two VCS, American Society of Mechanical Engineers ( ASME) Performance Test Codes PTC 22-2014, “Performance Te st Codes on Gas Turbines” and PTC 46-1996, “Performance Test Co des on Overall Plant Performance” are cited in the final r ule for their guidance on measuring the performance of stationary combustion turbines. These standards are available at http://w ww.asme.org*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 776 of 854 or by mail at American Society of Mechanical Engine ers (ASME), Two Park Avenue, New York, NY 10016-5990. One VCS, International Organization for Standardiza tion method ISO 2314:2009, “Gas Turbines - Acceptance Te sts” is cited in the final rule for its guidance on determining p erformance characteristics of stationary combusiton turbines. This standard is available at http://www.iso.org/iso/home.htm or by mail at International Organization for Standardization (ISO ), 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland. Since no EPA Methods were used, there was no need f or a NTTAA search. The rule also requires use of Appendicesappendices A, B, D, F and G to 40 CFR part 75 and the procedures under 40 CFR 98.33 ; these Appendicesappendices contain standards that have already been reviewed under the NTTAA. J. Executive Order 12898: Federal Actions to Addres s Environmental Justice in Minority Populations and L ow-Income Populations Executive Order 12898 (59 FR 7629; February 16, 199 4) establishes federal executive policy on environment al justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make en vironmental justice part of their mission by identifying and ad dressing, as appropriate, disproportionately high and adverse hu man health or environmental effects of their programs, policies , and*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 777 of 854 activities on minority populations and low-income p opulations in the U.S. The EPA defines environmental justice as t he fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respec t to the development, implementation, and enforcement of env ironmental laws, regulations, and policies. The EPA has this g oal for all communities and persons across this Nation. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access t o the decision-making process to have a healthy environme nt in which to live, learn, and work. Leading up to this rulemaking the EPA summarized th e public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment F inding, the Administrator considered climate change risks to mi nority or low-income populations, finding that certain parts of the population may be especially vulnerable based on th eir circumstances. ThesePopulations that were found to be particularly vulnerable to climate change risks include the poor, the elderly, the very young, those already in poor health, the disabled, those living alone, and/or indigenous populations dependent on one or a few resources. See Sections XIV. F and G, above, where the EPA discusses Consultation and Coordination with Tribal Governments and Protection of Children. The*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 778 of 854 Administrator placed weight on the fact that certai n groups, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. StrongThe record for the 2009 Endangerment Finding summarizes the strong scientific evidence that the potential impacts of climate change raise environmental justi ce issues is

found in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Pa nel on Climate Change (IPCC), and the National Research Co uncil (NRC) of the National Academies , summarized in the record for the Endangerment Finding. Their conclusions include tha t the potential impacts of climate change raise environme ntal justice issues. These reports concluded that poor communities can be especially vulnerable to climate change impacts bec ause they tend to have more limited adaptive capacities and a re more dependent on climate-sensitive resources such as lo cal water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, p articularly

those onimpacted by degradation of natural and cultural resources within established reservations that are restricted to reservation boundaries and therefore have limited relocation optionsthreats to traditional subsistence lifestyle s . Tribal communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 779 of 854 affected by the degradation of ecosystem goods and services associated with climate change. The 2009 Endangerment Finding record also specifi cally

noted that Southwest native cultures are especially vulnerable to water quality and availability impacts. Native A laskan communities are likely to experiencealready experiencing disruptive impacts, including coastal erosion and s hifts in the range or abundance of wild species crucial to their livelihoods and well-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations in the United States. 613 The new

613 Melillo, Jerry M., Terese (T.C.) Richmond, and Gar y W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp. IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C .B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T .E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, 1132 pp. IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects . Contribution of Working Group II to the Fifth Assessment Report of the Inte rgovernmental Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatter jee, K.L.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 780 of 854 assessment literature provides more detailed findin gs regarding these populations’ vulnerabilities and projected im pacts they may experience. In addition, the most recent assess ment literaturereports provides new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These studiesreports find that certain climate change related impacts—in cluding heat waves, degraded air quality, and extreme weather ev ents—have disproportionate effects on low-income and some com munities of color, raising environmental justice concerns. Exis ting health disparities and other inequities in these communiti es increase their vulnerability to the health effects of climat e change. In addition, the studiesassessment reports also find that climate change poses particular threats to health, wellbein g, and ways of life of indigenous peoples in the United States. As the scientific literature presented above and in the Endangerment Finding illustrates, low income commun ities and

some communities of color are especially vulnerable to t he health and other adverse impacts of climate change.

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kiss el, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. Whi te (eds.)]. Cambridge University Press, 688 pp.*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 781 of 854 The EPA believes the human health or environmental risk addressed by this final action will not have potent ial disproportionately high and adverse human health or environmental effects on minority, low-income or in digenous populations. The final rule limits GHG emissions fr om newly constructed, modified, and reconstructed fossil fue l-fired electric utility steam generating units and natural gasfirednewly constructed and modified stationary combustion turbines by establishing national emission standard s for CO 2 . The EPA has determined that the final rule will not result in disproportionately high and adverse human health or environmental effects on minority, low-income or in digenous populations because the rule is not anticipated to notably affect the level of protection provided to human he alth or the environment. The EPA believes that electric power c ompanies will choose to build new fossil fuel-fired electric util ity steam generating units and natural gas-fired stationary c ombustion turbines that comply with the regulatory requiremen ts of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam g enerating units without CCS to be built and expects that any newly built natural gas-fired stationary combustion turbines wi ll meet the standards. In addition, as previously stated, the E PA expects few modified or reconstructed fossil fuel-fired electric utility*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 782 of 854 steam generating units or natural gas-fired station ary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. This final rule will ensure that, to whatever extent there are newly constructed, modified, and reconstructed EGUs, they will use the best performing technologies to limit emissions of CO 2 . K. Congressional Review Act (CRA) This final action is subject to the CRA, and the EP A will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This acti on is not a “major rule” as defined by 5 U.S.C. 804(2). XIIIXV. Withdrawal of Proposed Standards for Certai n Modified

Sources In this action, as discussed above in Sections IV a nd VI, the EPA is issuing final standards of performance f or affected fossil fuel-fired steam generating EGUs that implem ent modifications resulting in an increase of CO 2 emissions (in lb/hr) of more than 10 percent. In addition, the EP A is withdrawing the proposed standards of performance f or emissions of carbon dioxide (CO 2 ) from modified fossil fuel-fired EGUs not covered by those final standards. Specifically, the EPA is withdrawing the proposed standards for fossil fuel- fired steam generating EGUs that implement modifications result ing in an increase of CO 2 emissions (in lb/hr) of less than or equal to 10*** EO 12866 _ Review - Draft – Do Not Cite, Quote or Release Duri ng Review ***

Page 783 of 854 percent. A detailed rationale for the withdrawal of these proposed standards is provided in Section VI above. The EPA is also, in this action, withdrawing propos ed standards for modified stationary combustion turbin es. A detailed rationale for the withdrawal of these prop osed standards is provided in Section IX above. The proposed standards for modified fossil fuel-fir ed EGUs that the EPA is withdrawing in this action were pub lished in the Federal Register on June 18, 2014 (79 FR 34960).

XVI . Statutory Authority The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This a ction is also subject to section 307(d) of the CAA (42 U.S.C. 760 7(d)).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review ***

Standards of Performance for Greenhouse Gas Emissio ns from New, Modified, and Reconstructed Stationary Sources: Ele ctric Utility Generating Units Page 784 of 854 List of Subjects

40 CFR Part 60 Environmental protection, Administrative practice a nd procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordke eping requirements. 40 CFR Part 70 Environmental protection, Administrative practice a nd procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements. 40 CFR Part 71 Environmental protection, Administrative practice a nd procedure, Air pollution control, Reporting and rec ordkeeping requirements. 40 CFR Part 98 Environmental protection, Greenhouse gases and moni toring, Reporting and recordkeeping requirements.

Dated :__________________.: __________________.

________________________ Gina McCarthy, Administrator*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 785 of 854

For the reasons stated in the preamble, title 40, c hapter I, part 60, 70, 71, and 98 of the Code of the Federal Regulations is amended as follows:

PART 60-- STANDARDS OF PERFORMANCE FOR NEW STATIONA RY SOURCES 1. The authority citation for part 60 continues to read as

follows: Authority: 42 U.S.C. 7401, et seq. 2. Section 60.17 is amended by: a. Redesignating paragraphs (d) through (t) as para graphs (e) through (u) and adding new paragraphs (d) and ( d)(1); b. In redesignated paragraph (g), further redesigna ting paragraph (g)(15) as paragraph (g)(17) and adding n ew paragraphs (g)(15) and (g)(16); c. In redesignated paragraph (h), revising paragrap hs (h)(37), (h)(42), (h)(46), (h)(138), (h)(187), and (h)(190); and c. In redesignated paragraph (m), further redesigna ting paragraph (m)(1) as paragraph (m)(2) and adding new paragraph (m)(1). The additions read as follows: §60.17 Incorporations by reference.

* * * * **** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 786 of 854 (d) The following material is available for purchas e from the American National Standards Institute (ANSI), 2 5 W. 43rd Street, 4th Floor, New York, NY, 10036, Telephone ( 212) 642- 4980, and is also available at the following Web si te: http://www.ansi.org (1) ANSI No. C12.20-2010 American National Standard for Electricity Meters--0.2 and 0.5 Accuracy Classes (A pproved August 31, 2010), IBR approved for §60.5535(d).

* * * * * (g) * * * (15) ASME PTC 22-2014, Gas Turbines: Performance Te st Codes, (Issued December 31, 2014), IBR approved for §60.5535(h). (16) ASME PTC 46-1996, Performance Test Code on Ove rall Plant Performance, (Issued November 28, 1996), IBR approved for §60.5535(h).

* * * * * (h) * * * (37) ASTM D388-99 (Reapproved 2004) ε ,1 Standard Specification for Classification of Coals by Rank, IBR approved for §§60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, 60. 251, and 60.5580.

* * * * **** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 787 of 854 (42) ASTM D396-98, Standard Specification for Fuel Oils, IBR approved for §§60.41b, 60.41c, 60.111(b), 60.11 1a(b), and 60.5580.

* * * * * (46) ASTM D975-08a, Standard Specification for Dies el Fuel Oils, IBR approved for §§60.41b 60.41c, and 60.5580

. * * * * * (138) ASTM D3699-08, Standard Specification for Ker osine, including Appendix X1, (Approved September 1, 2008) , IBR approved for §§60.41b, 60.41c, and 60.5580.

* * * * * (187) ASTM D6751-11b, Standard Specification for Bi odiesel Fuel Blend Stock (B100) for Middle Distillate Fuels , including Appendices X1 through X3, (Approved July 15, 2011), IBR approved for §§60.41b, 60.41c, and 60.5580.

* * * * * (190) ASTM D7467-10, Standard Specification for Die sel Fuel Oil, Biodiesel Blend (B6 to B20), including Appendi ces X1 through X3, (Approved August 1, 2010), IBR approved for §§60.41b, 60.41c, and 60.5580.

* * * * * (m) * * **** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 788 of 854 (1) ISO 2314:2009, Gas turbines–Acceptance tests, ( Issued December 15, 2009), IBR approved for §60.5535(h).

* * * * * 3. Part 60 is amended by adding subpart TTTT to read a s follows: Subpart TTTT Standards of Performance for Greenhous e Gas Emissions for Electric Utility Generating Units

Sec. Applicability § 60.5508 What is the purpose of this subpart? § 60.5509 Am I subject to this subpart? Emission Standards § 60.5515 Which greenhouse gases pollutants are regulated by this

subpart? § 60.5520 What CO 2 emissions standard must I meet? General Compliance Requirements § 60.5525 What are my general requirements for comply ing with

this subpart? Monitoring and Compliance Determination Procedures § 60.5535 How do I monitor and collect data to demons trate

compliance? § 60.5540 How do I demonstrate compliance with my CO 2 emissions

standard and determine excess emissions? Notifications, Reports, and Records § 60.5550 What notifications must I submit and when? § 60.5555 What reports must I submit and when? § 60.5560 What records must I maintain? § 60.5565 In what form and how long must I keep my re cords?*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 789 of 854 Other Requirements and Information § 60.5570 What parts of the General Provisions apply to my affected EGU? § 60.5575 Who implements and enforces this subpart? § 60.5580 What definitions apply to this subpart?

Applicability § 60.5508 What is the purpose of this subpart? This subpart establishes emission standards and com pliance schedules for the control of greenhouse gas (GHG) e missions from a steam generating unit, IGCC, or a stationary comb ustion turbine that commences construction after January 8 , 2014 or commences modification or reconstruction after June 18, 2014. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to

as an affected EGU. § 60.5509 Am I subject to this subpart? (a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart apply to any steam generating unit, IGCC, or stationary combusti on turbine that commenced construction after January 8, 2014 o r commenced

modification or reconstruction after June 18, 2014 that meets the relevant applicability conditions in paragraphs (a) (1) and (a)(2) of this section. The GHG standards included in this subpart also apply to any steam generating unit or IGCC that*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 790 of 854 commenced modification after June 18, 2014 that mee ts the relevant applicability conditions in paragraphs (a) (1) and (a)(2) of this section. (1) Has a base load rating greater than 260 GJ/h (2 50 MMBtu/h) of fossil fuel (either alone or in combina tion with any other fuel), and (2) Serves a generator capable of selling greater t han 25 MW of electricity to a utility power distribution s ystem. (b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions sp ecified in paragraphs (b)(1) through (b)( 9 8 ) of this section. (1) Your EGU is a steam generating unit or IGCC tha t is currently and always has been subject to a federall y enforceable permit condition limiting annual net-electric sales to no more than one-third or less of its potential electric output or 219,000 MWh or less on an annual basis , whichever is greater

. (2) Your EGU is capable of combusting 90% 50 percent or more non-fossil fuel and is also subject to a federally enforceable permit condition limiting fossil fuel use to 10% or less of the annual capacity factor

. for all fossil fuels combined of 10 percent (0.10) or less. (3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 791 of 854 annual net-electric sales to no more than the product of the unit's net design efficiency times and the unit's potential electric output or 219,000 MWh ( , whichever is greater ) or less . (4) Your EGU serves a generator along with other st eam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less. (5) Your EGU is a municipal waste combustor unit that is subject to subpart Eb of this part. (6) Your EGU is a commercial or industrial solid wa ste incineration unit that is subject to subpart CCCC o f this part. (7) Modified units that conduct modifications Your EGU is a steam generating unit or IGCC that undergoes a modi fication resulting in a potential an hourly increase in CO 2 emissions (mass per hour) of 10 percent or less (2 significant figures). Modified units that are not subject to the requirem ents of this subpart pursuant to this subsection continue to be existing units under section 111 with respect to CO 2 emissions standards

. (8) Your EGU is a stationary combustion turbine tha t is subject to a federally enforceable permit limiting annual net-electric sales to the design efficiency times the potential electric output or less as net-electrical sales.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 792 of 854 (9) Your stationary combustion turbine is not capable of combusting natural gas (e.g., not connected to a na tural gas pipeline). (9) The proposed Washington County EGU project desc ribed in Air Quality Permit No. 4911–303–0051–P–01–0 issued by the Georgia Department of Natural Resources, Environmen tal Protection Division, Air Protection Branch, effecti ve April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (10) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of E nvironment, effective December 16, 2010, provided that construc tion had not commenced for NSPS purposes as of January 8, 2014. Emission Standards § 60.5515 Which greenhouse gases pollutants are regulated by this subpart? (a) The greenhouse gas pollutants regulated by this subpart are greenhouse gases. The greenhouse gas standard i n this subpart is in the form of a limitation on emission of carbon dioxide (CO 2 ). . (b) PSD and Title V Thresholds for Greenhouse Gases

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 793 of 854 (1) For the purposes of § 51.166(b)(49)(ii) of this chapter, with respect to GHG emissions from affecte d EGUs, the “pollutant that is subject to the standard prom ulgated under section 111 of the Act” shall be considered t o be the pollutant that otherwise is subject to regulation u nder the Act as defined in § 51.166(b)(48) and in any SIP ap proved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48) of this chapter. (2) For the purposes of § 52.21(b)(50)(ii) of this chapter,(1) For the purposes of 40 CFR §51.166(b)(4 9)(ii), with respect to GHG emissions from affected facilit ies, the “pollutant that is subject to the standard promulga ted under section 111 of the Act” shall be considered t o be the pollutant that otherwise is subject to regulation u nder the Act as defined in § 52.21(b)(4951.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorpor ate, or specifically incorporates, §51.166(b)(48 ) of this chapter. (3) For the purposes of § 70.2 of this chapter (2) For the purposes of 40 CFR §52.21(b)(50)(ii), with respect to GHG emission s from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is su bject to*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 794 of 854 regulation under the Act as defined in §52.21(b)(49 ) of this chapter. (3) For the purposes of 40 CFR §70.2 of this chapte r, with respect to greenhouse gas emissions from affected f acilities, the “pollutant that is subject to any standard prom ulgated under section 111 of the Act” shall be considered to be t he pollutant that otherwise is "subject to regulation" as define d in 40 CFR §70.2 of this chapter. (4) For the purposes of 40 CFR §71.2 , with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulga ted under section 111 of the Act” shall be considered to be t he pollutant that otherwise is "subject to regulation" as define d in § 70 40 CFR §71 .2 of this chapter. (4) For the purposes of § 71.2, with respect to gre enhouse gas emissions from affected facilities, the “pollut ant that is subject to any standard promulgated under section 1 11 of the Act” shall be considered to be the pollutant that o therwise is "subject to regulation" as defined in § 71.2 of thi s chapter. § § 60.5520 What CO 2 emission standard must I meet? (a) For each affected EGU subject to this subpart, you must not discharge from the affected EGU any gases that contain CO 2 in excess of the applicable CO 2 emission standard specified in*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 795 of 854 Table 1 or Table 2 of this subpart, consistent with paragraphs (b ) ), (c), and ( c d ) of this section, as applicable. (b) Except as specified in paragraph paragraphs (c) and (d)

of the this section, you must comply with the applicable gross energy output standard and your operating permit mu st include monitoring, recordkeeping, and reporting methodolog ies based on the applicable gross energy output standard. For th e remainder of this subpart , (for sources that do not qualify under paragraphs (c) and (d) of this section), where the term “gross or net energy output” is used, the term that applie s to you is “gross energy output .” ”.” (c) As an alternate to meeting the requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the pe tition, the

source will beginning on the date the Administrator grants the petition have to , the affected EGU must comply with the applicable net energy output based standard include d in this subpart. Your operating permit must include monitor ing, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the rema inder of this subpart, where the term “gross or net energy output ” is used,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 796 of 854 the term that applies to you is “net energy output. ” Owners or operators complying with the net output based stand ard must petition the Administrator to switch back to comply ing with the gross energy output based standard. (d) Stationary combustion turbines subject to a hea t input based standard in Table 2 that are only permitted t o burn one or more of the fuels listed in paragraph (d)(1) of thi s section are only subject to the monitoring requirements in para graph (d)(1) of this section. All other stationary combustion tu rbines subject to a heat input based standard in Table 2 a re subject to the requirements in paragraph (d)(2) of this sectio n. (1) Stationary combustion turbines that are only pe rmitted to burn fuels with a consistent chemical compositio n (i.e., uniform fuels) that result in a consistent emission rate of 160

lb CO 2 /MMBtu or are not subject to any monitoring or repo rting requirements under this subpart. These fuels includ e, but are not limited to, natural gas, methane, butane, butyl ene, ethane, ethylene, propane, naphtha, propylene, jet fuel ker osene, distillate oil No. 1, No. 2, and biodiesel. Station ary combustion turbines qualifying under this paragraph are only required to maintain purchase records for permitted fuels. (2) Stationary combustion turbines permitted to bur n fuels that do not have a consistent chemical composition or that do*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 797 of 854 have an emission rate of 160 lb CO 2 /MMBtu or less (e.g., nonuniform fuels such as residual oil and non-jet fuel kerosene) must follow the monitoring, recordkeeping, and repo rting requirements necessary to complete the heat input b ased calculations under this subpart. General Compliance Requirements § 60.5525 What are my general requirements for comply ing with this subpart? Compliance Combustion turbines qualifying under § 60.5520(d)(1) are not subject to any requirements i n this section other than the requirement to maintain fuel purchase records for permitted fuel(s). For all other affect ed sources, compliance with the applicable CO 2 emission standard of this subpart shall be determined on a 12-operating

- month rolling average basis. See Tables Table 1

- or 2 for the applicable CO 2 emission standards. (a) You must be in compliance with the emission sta ndards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emi ssion standards only at the end of the applicable operati ng month, as provided in paragraph (a)(1). (1) For each affected EGU subject to a CO 2 emissions standard based on a 12-operating

- month rolling average, you must*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 798 of 854 determine compliance monthly by calculating the ave rage CO 2 emissions rate for the affected EGU at the end of t he initial and each subsequent 12-operating

- month period. (2) Consistent with §60.5520(d)(2), if your affecte d stationary combustion turbine is subject to an inpu t-based CO 2 emissions standard, you must determine the total he at input in million Btu’s (MMBtu) from natural gas (HTIP ng ) and the total heat input from all other fuels combined (HTIP o ) using one of the methods under §60.5535(d)(2). You must then use the following equation to determine the applicable emissions stan dard during the compliance period:

 emission	standard	= 120		x	HTIP   +  160		x	HTIP   HTIP  + HTIP

 Where:

CO 2 emission standard = the emission standard during t he

compliance period in units of lb/MMBtu.

HTIP ng = the heat input in MMBtu from natural gas.

HTIP o = the heat input in MMBtu from all fuels other tha n

natural gas. 120 = allowable emission rate in lbs of CO 2 /MMBtu for heat

input derived from natural gas. 160 = allowable emission rate in lbs of CO 2 /MMBtu for heat

input derived from all fuels other than natural

gas.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 799 of 854 (b) At all times you must operate and maintain each affected EGU, including associated equipment and monitoring equipment monitors , in a manner consistent with safety and good air pollution control practice. The Administrator w ill determine if you are using consistent operation and maintenan ce procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, m onitoring results, review of operation and maintenance proced ures and records, review of reports required by this subpart , and inspection of the EGU. (c) Within 30 days after the end of the initial com pliance period (i.e., no more than 30 days after the first 12-operating

- month compliance period), you must make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in Table 1 or Table 2 of this subpart, in accordance with the requirements in thi s subpart. The first operating month included in the initial 1 2-operating

- month compliance period shall be determined as foll ows: (1) For an affected EGU that commences commercial o peration (as defined in §72.2 of this chapter) on or after t he effective date of this rule, the first month of the initial c ompliance period shall be the first operating month (as defin ed in §60.5580) after the calendar month in which emissio ns reporting*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 800 of 854 is required to begin under: (i) §63.5555(c)(3)(i), for units subject to the Aci d Rain Program; or (ii) §63.5555(c)(3)(ii)(A), for units that are not in the Acid Rain Program. (2) For an affected EGU that has commenced commerci al operation (as defined in §72.2 of this chapter) pri or to the effective date of this rule: (i) If the date on which emissions reporting is req uired to begin under §75.64(a) of this chapter has passed pr ior to the effective date of this rule, emissions reporting sh all begin according to §63.5555(c)(3)(i) (for Acid Rain progr am units), or according to §63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain Program). The first month of the initial compliance period shall be the first operat ing month (as defined in §60.5580) after the calendar month in wh ich the rule becomes effective; or (ii) If the date on which emissions reporting is re quired to begin under §75.64(a) of this chapter occurs on or after the effective date of this rule, then the first month o f the initial compliance period shall be the first operating mont h (as defined in §60.5580) after the calendar month in which emis sions reporting is required to begin under §63.5555(c)(3) (ii)(A).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 801 of 854 (3) For a modified or reconstructed EGU that become s subject to this subpart, the first month of the ini tial compliance period shall be the first operating mont h (as defined in §60.5580) after the calendar month in which emis sions reporting is required to begin under §63.5555(c)(3) (iii). Monitoring and Compliance Determination Procedures § 60.5535 How do I monitor and collect data to demons trate compliance? (a) You (a) Combustion turbines qualifying under §60.5520(d)(1) are not subject to any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). If your combustion t urbine uses non-uniform fuels as specified under §60.5520(d)(2) , you must monitor heat input in accordance with paragraph (c) (1) of this section, and you must monitor CO 2 emissions in accordance with either paragraph (b), (c)(2), or (c)(5) of this sec tion. For all other affected sources, you must prepare a monitoring plan to quantify the hourly CO 2 mass emission rate (tons/ hr h ), in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. The electronic portion of the monitoring plan must be submitted using the ECMPS Client Tool and m ust be in place prior to reporting emissions data and/or the results of monitoring system certification tests under this su bpart. The*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 802 of 854 monitoring plan must be updated as necessary. Monitoring plan submittals must be made by the Designated Represent ative (DR), the Alternate DR, or a delegated agent of the DR (s ee §60.5555(c)). (b) You must determine the hourly CO 2 mass emissions in kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1) through (5) of this section, or, if applicab le, as provided in paragraph (c) of this section. (1) For an affected coal-fired EGU or for an IGCC u nit you must, and for all other affected EGUs you may, inst all, certify, operate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and re cord hourly average CO 2 concentrations in the affected EGU exhaust gases emitted to the atmosphere, and a flow monitoring sy stem to measure hourly average stack gas flow rates, accord ing to § 75.10(a)(3)(i) of this chapter. As an alternative t o direct

measurement of CO 2 concentration, provided that your EGU does not use carbon separation (e.g., carbon capture and sto rage), you may use data from a certified oxygen (O 2 ) monitor to calculate hourly average CO 2 concentrations, in accordance with §75.10(a)(3)(iii) of this chapter. If you measure C O 2 concentration on a dry basis, you must also install , certify, operate, maintain, and calibrate a continuous moist ure*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 803 of 854 monitoring system, according to § 75.11(b) of this chapter. 75.11(b) of this chapter. Alternatively, you may either use an appro priate fuelspecific default moisture value from §75.11(b) or s ubmit a petition to the Administrator under §75.66 of this chapter for a site-specific default moisture value. (2) For each continuous monitoring system that you use to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and appendices A and B to part 75 of this c hapter. (3) You must use only unadjusted exhaust gas volume tric flow rates to determine the hourly CO 2 mass emissions rate from the affected EGU; you must not apply the bias adjus tment factors described in Section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (4) You must select an appropriate reference method to setup (characterize) the flow monitor and to perfor m the ongoing RATAs, in accordance with part 75 of this cha pter. If you use a Type-S pitot tube or a pitot tube assembly fo r the flow RATAs, you must calibrate the pitot tube or pitot t ube assembly; you may not use the 0.84 default Type-S pitot tube coefficient specified in Method 2. (5) Calculate the hourly CO 2 mass emissions (kg) as described in paragraphs (a)(6)(i) through (iv) of t his section.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 804 of 854 Perform this calculation only for “valid operating hours”, as defined in §60.5540(a)(1). (i) Begin with the hourly CO 2 mass emission rate (tons/ hr h ), obtained either from Equation F-11 in Appendix F to part 75 of this chapter (if CO 2 concentration is measured on a wet basis), or by following the procedure in section 4.2 of App endix F to part 75 of this chapter (if CO 2 concentration is measured on a dry basis). (ii) Next, multiply each hourly CO 2 mass emission rate by the EGU or stack operating time in hours (as define d in §72.2 of this chapter), to convert it to tons of CO 2. (iii) Finally, multiply the result from paragraph (b)(5)(ii) of this section by 909.1 to convert it f rom tons of

CO 2 to kg. Round off to the nearest kg. (iv) The hourly CO 2 tons/ hr h values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6). You must use these data to calculate the hourly CO 2 mass emissions. (c) If your affected EGU exclusively combusts liqui d fuel and/or gaseous fuel , as an alternative to complying with paragraph (b) of this section, you may determine th e hourly CO 2 mass emissions according to paragraphs (c)(1) throu gh (4) of*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 805 of 854 this section. If you use non-uniform fuels as specified in §60.5520(d)(2) you may determine CO 2 mass emissions during the compliance period according to paragraph (c)(5) of this section. (1) You (1) If you are subject to an output based standard and you do not install CEMS in accordance with para graph (b),

you must implement the applicable procedures in append ix D to part 75 of this chapter to determine hourly EGU hea t input rates (MMBtu/h), based on hourly measurements of fuel flo w rate and periodic determinations of the gross calorific valu e (GCV) of

each fuel combusted. (2) For each measured hourly heat input rate, use E quation G-4 in Appendix G to part 75 of this chapter to cal culate the hourly CO 2 mass emission rate (tons/ hr). h). You may determine site-specific carbon-based F-factors (F c ) using Equation F-7b in section 3.3.6 of appendix F to part 75 of this chap ter, and you may use these F c values in the emissions calculations instead of using the default F c values in the Equation G-4 nomenclature. (3) For each “valid operating hour” (as defined in §60.5540(a)(1), multiply the hourly tons/h CO 2 mass emission rate from paragraph (c)(2) of this section by the EGU or stack operating time in hours (as defined in §72.2 of thi s chapter), to convert it to it to tons of CO 2 . Then, multiply the result by*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 806 of 854 909.1 to convert from tons of CO 2 to kg. Round off to the nearest two significant figures. (4) The hourly CO 2 tons/h values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6) You must use these data to calculate the hourly CO 2 mass emissions. (5) If you operate a combustion turbine firing non- uniform fuels, as an alternative to following paragraphs (c )(1)through (4) of this section, you may determine CO 2 emissions during the compliance period using one of the following method s: (i) Units firing fuel gas may determine the heat in put during the compliance period following the procedur e under §60.107a(d) and convert this heat input to CO 2 emissions using Equation G-4 in Appendix G to Part 75. (ii) You may use the procedure for determining CO 2 emissions during the compliance period based on the use of th e Tier 3 methodology under §98.33(a)(3). (d) Consistent with § 60.5520, you must determine the basis of the emissions standard that applies to your affe cted source in accordance with either paragraph (d)(1) or (d)(2 ), as applicable: (1) If you operate a source subject to an emissions*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 807 of 854 standard established on an output basis (e.g., lbs of CO 2 per gross or net MWh of energy output), you must install, calibrate, maintain, and operate a sufficient number of watt m eters to continuously measure and record the hourly gross el ectric output or net electric output, as applicable, from the aff ected EGU(s). These measurements must be performed using 0.2 clas s electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20

. (incorporated by reference, see 60.17). For a combined heat and power (CHP) EGU, as define d in §60.5580, you must also install, calibrate, maintai n, and operate meters to continuously (i.e., hour-by-hour) determine and record the total useful thermal output. For pro cess steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record the hourly steam flow rate, temperature, and pressure. Your pl an shall ensure that you install, calibrate, maintain, and o perate meters to record each component of the determination, hour -by-hour. (2) If you operate a source subject to an emissions standard established on a heat-input basis (e.g., l b CO2/MMBtu) and your affected source uses non-uniform heating v alue fuels as delineated under §60.5520(d), you must determine th e total heat input for each fuel fired during the compliance per iod in accordance with one of the following procedures:*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 808 of 854 (i) Appendix D to Part 75; (ii) The procedures for monitoring heat input under of §60.107a(d); (iii) If you monitor CO 2 emissions in accordance with the Tier 3 methodology under §98.33(a)(3), you may conv ert your CO 2 emissions to heat input using the appropriate emiss ion factor in Table C-1 of Part 98. If your fuel is not listed in Table C-1, you must determine a fuel-specific carbon-based F-f actor (F c ) in accordance with section 12.3.2 of EPA Method 19 of appendix A-7 to part 60, and you must convert your CO 2 emissions to heat input using Equation G-4 in Appendix G to Part 75. (e) Consistent with § 60.5520, if two or more affected EGUs serve a common electric generator, you must apporti on the combined hourly gross or net energy output to the i ndividual affected EGUs according to the fraction of the tota l steam load contributed by each EGU. Alternatively, if the EGU s are identical, you may apportion the combined hourly gr oss or net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU. (f) In accordance with § 60.13(g) and § 60.5520, if two or more affected EGUs that implement the continuous em ission monitoring provisions in paragraph (b) of this sect ion share a common exhaust gas stack and are subject to the sam e emissions*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 809 of 854 standard in Table 1 or Table 2 of this subpart, you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If you choose this option, the hourly gross or net energy output (electric, therma l, and/or mechanical, as applicable) must be the sum of the h ourly loads for the individual affected EGUs and you must expre ss the operating time as “stack operating hours” (as defin ed in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected EGU sharing the stack is in compliance. (g) In accordance with § 60.13(g) and § 60.5520 if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragr aph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a com mon stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must de termine compliance with the applicable emissions standard i n Table 1 or 2 of this subpart by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 810 of 854 §60.5540 How do I demonstrate compliance with my CO 2 emissions standard? (a) In accordance with § 60.5520, if you are subject to an output based emission standard or you burn non-unif orm fuels as specified in § 60.5520(d)(2) you must demonstrate compliance with the applicable CO 2 emission standard in Table 1 or 2 of this subpart , for as required in this section. For the initial and each subsequent 12-operating

- month rolling average compliance period, you must follow the procedures in paragraph s (a)(1) through (a)(7) of this section to calculate the CO 2 mass emissions rate for your affected EGU(s) in units of the applicable emissions standard ( i.e., either kg/MWh or lb/MMBtu ). You must use the hourly CO 2 mass emissions calculated under §60.5535(b) or (c), as applicable, and generation either the generating load data from §60.5535 in the (d)(1) for output-based calculations or the heat input data from §60.5535(d)(2) for heat-input-based calculations. Combustion turbines firing nonuniform fuels that contain CO 2 prior to combustion (e.g., blast furnace gas or landfill gas) may sample the fuel st ream to determine the quantity of CO 2 present in the fuel prior to combustion and exclude this portion of the CO 2 mass emissions from compliance determinations

.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 811 of 854 (1) Each compliance period shall include only “vali d operating hours” in the compliance period, i.e., op erating hours for which: (i) “Valid data” (as defined in §60.5580) are obtai ned for all of the parameters used to determine the hourly CO 2 mass emissions (kg ); and ) and, if a heat input based standard applies, all the parameters used to determine total heat inp ut for the hour are also obtained; and (ii) The corresponding hourly gross or net energy o utput value is also valid data (Note: for hours with no u seful output, zero is considered to be a valid value). (2) You must exclude operating hours in which: (i) The substitute data provisions of part 75 of th is chapter are applied for any of the parameters used to determine the hourly CO 2 mass emissions or, if a heat input based standard applies, for any parameters used to determine the h ourly heat input ; or (ii) An exceedance of the full-scale range of a con tinuous emission monitoring system occurs for any of the pa rameters used to determine the hourly CO 2 mass emissions or, if applicable, to determine the hourly heat input ; or (iii) The total gross or net energy output (P gross/net ) or, if applicable, the total heat input is unavailable.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 812 of 854 (3) For each compliance period, at least 95 percent of the operating hours in the compliance period must be va lid operating hours, as defined in paragraph (a)(1) of this secti on. (4) You must calculate the total CO 2 mass emissions by summing the valid hourly CO 2 mass emissions values from §60.5535 for all of the valid operating hours in the complia nce period. (5) (5) Sources subject to output based standards. For each valid operating hour of the compliance period that was used in paragraph (a)(4) of this section to calculate the t otal CO 2 mass emissions, you must determine P gross/net (the corresponding hourly gross or net energy output in MWh) according to the procedures in paragraphs (a)(3)(i) and (ii) of this section, a s appropriate for the type of affected EGU(s). For an operating h our in which a valid CO 2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, if there is no gross or net electrical output, but there is mechanical or usefu l thermal output, you must still determine the gross or net e nergy output for that hour. In addition, for an operating hour i n which a valid CO 2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, but there is n o (i.e., zero) gross electrical, mechanical, or useful therm al output, you must use that hour in the compliance determinat ion. For hours or partial hours where the gross electric out put is equal*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 813 of 854 to or less than the auxiliary loads, net electric o utput shall be counted as zero for this calculation. (i) Calculate P gross/net for your affected EGU using the following equation. All terms in the equation must be expressed in units of megawatt-hours (MWh). To convert each hourly gross or net energy output (Consistent with § 60.5520) value reported under part 75 of this chapter to MWh, multiply by t he corresponding EGU or stack operating time.  / =     +     +    ! −  #$    %& +    & +    '( −   )* T −  + TDF + .  /  0 +  /  12 +  /  ! 3

Where: a

P gross/net = In accordance with § 60.5520, gross or net energy

output of your affected EGU for each valid operating hour (as defined in 60.5540(a)(1)) in

MWh. (Pe) ST = Electric energy output plus mechanical energy

output (if any) of steam turbines in MWh. (Pe) CT = Electric energy output plus mechanical energy

output (if any) of stationary combustion turbine(s) in MWh. (Pe) IE = Electric energy output plus mechanical energy*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 814 of 854 output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (Pe) FW = Electric energy used to power boiler feedwater

pumps at steam generating units in MWh. Not applicable to stationary combustion turbines, IGCC EGUs, or EGUs complying with a net energy output based standard. (Pe) A = Electric energy used for any auxiliary loads in

MWh. Not applicable for determining P gross . (Pt) PS = Useful thermal output of steam (measured relativ e

to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh. (Pt) HR = Non steam useful thermal output (measured

relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 815 of 854 (Pt) IE = Useful thermal output (relative to SATP

conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh.

T TDF = Electric Transmission and Distribution Factor

.

T = of 0.95 for a combined heat and power affected

EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12- operating

- month rolling average basis , or 1.0 for

all other affected EGUs

. T = 1.0 for all other affected EGUs.

(ii) If applicable to your affected EGU , (for example, for combined heat and power), you must calculate (Pt) PS using the following equation: / 0 = 5 6 × 8 3. 6 × 10 9 = 5 < ×	 8

) Where:*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 816 of 854 Q m = Measured steam flow in kilograms (kg) (or pound s

(lb)) for the operating hour. H = Enthalpy of the steam at measured temperature and

pressure (relative to SATP conditions or the energy in the condensate return line , as applicable) in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 10 9 CF = Conversion factor ( of 3.6 x 10 9 J/MWh ) ( or

3.413 x 10 6 Btu/MWh ). .

(6) Calculation of annual basis for standard. Sources complying with energy output-based standards must c alculate the basis (i.e., denominator) of their actual annual em ission rate in accordance with paragraph (6)(i). Sources comply ing with heat input based standards must calculate the basis of t heir actual annual emission rate in accordance with paragraph ( 6)(ii). (i) In accordance with § 60.5520 if you are subject to an output based standard , you must calculate the total gross or net energy output for the affected EGU’s compliance per iod by summing the hourly gross or net energy output value s for the affected EGU that you determined under paragraph (a )(5) of this section for all of the valid operating hours in the applicable compliance period.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 817 of 854 (7) You (ii) If you are subject to a heat input based stand ard, you must calculate the total heat input for each fu el fired during the compliance period. The calculation of to tal heat input for each individual fuel must include all val id operating hours and must also be consistent with any fuel-spe cific procedures specified within your selected monitorin g option under §60.5535(d)(2). (7) If you are subject to an output based standard, you must calculate the CO 2 mass emissions rate for the affected EGU(s) (kg/MWh) by dividing the total CO 2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total gross or net energy outpu t value calculated according to the procedures in paragraph (a)(6 ) of this section. Round off the result )(i) of this section. Round off the result to two significant figures if the calculated value is less than 1,000; round the result to three significant figure s if the calculated value is greater than 1,000. If you are subject to a heat input based standard, you must calculate the C O 2 mass emissions rate for the affected EGU(s) (lb/MMBtu) b y dividing

the total CO 2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by t he total heat input calculated according to the procedures in par agraph (a)(6)(ii) of this section. Round off the result to two*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 818 of 854 significant figures. (b) In accordance with § 60.5520, to demonstrate compliance with the applicable CO 2 emission standard, for the initial and each subsequent 12-operating

- month compliance period, the CO 2 mass emissions rate for your affected EGU must be d etermined according to the procedures specified in paragraph (a)(1) through (7) of this section and must be less than o r equal to the applicable CO 2 emissions standard in Table 1 , Table 2, or 2 the emissions standard calculated in accordance with §60.5525(a)(2) of this subpart. Notification, Reports, and Records § 60.5550 What notifications must I submit and when? (a) You must prepare and submit the notifications speci fied in § 60.7(a)(1) and (a)(3) and § 60.19, as applicable to your affected EGU(s) (see Table 3 of this Subpart). (b) You must prepare and submit notifications speci fied in § 75.61 of this chapter, as applicable to your affect ed EGUs. § 60.5555 What reports must I submit and when? (a) You must prepare and submit reports according t o paragraphs (a) through (d) of this section, as appl icable. (1) For affected EGUs that are required by § 60.5525 to conduct initial and on-going compliance determinati ons on a 12- operating

- month rolling average basis, you must submit*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 819 of 854 electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the a ffected EGU, you must submit a report for the calendar quarter t hat includes the twelfth operating month no later than 30 days a fter the end of that quarter. Thereafter, you must submit a repo rt for each subsequent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report you must include the f ollowing information, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last (twelfth) operating month in a 12-operatin g

- month compliance period falls within the calendar quarter . You must calculate each average CO 2 mass emissions rate for the compliance period according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth operating months in each compliance period for which you perf ormed a CO 2 mass emissions rate calculation. If there are no co mpliance periods that end in the quarter, you must include a statement to that effect; (ii) If one or more compliance periods end in the q uarter you must identify each operating month in the calen dar quarter where your EGU violated the applicable CO 2 emission standard; (iii) If one or more compliance periods end in the quarter*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 820 of 854 and there are no violations for the affected EGU, y ou must include a statement indicating this in the report; (iv) The percentage of valid operating hours in eac h 12- operating

- month compliance period described in paragraph (a)(1)(i) of this section (i.e., the total number o f valid operating hours (as defined in §60.5540(a)(1)) in t hat period divided by the total number of operating hours in t hat period, multiplied by 100 percent); (v) Consistent with § 60.5520, the CO 2 emissions standard (as identified in Table 1 or 2) with which your aff ected EGU must comply; and (vi) Consistent with § 60.5520, an indication whether or not the hourly gross or net energy output (P gross/net ) values used in the compliance determinations are based solely upon gross electrical load. (3) In the final quarterly report of each calendar year, you must include the following: (i) Consistent with § 60.5520, gross energy output or net energy output sold to an electric grid , as applicable to the units of your emission standard, over the 4 quarters of the calendar year; and (ii) The potential electric output of the EGU. (b) You must submit all electronic reports required under*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 821 of 854 paragraph (a) of this section using the Emissions C ollection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric P rograms of

EPA. (c) (1) For affected EGUs under this subpart that a re also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as requir ed under subpart G of part 75 of this chapter. (2) For affected EGUs under this subpart that are n ot in the Acid Rain Program, you must also meet the repor ting requirements and submit reports as required under s ubpart G of part 75 of this chapter, to the extent that those r equirements and reports provide applicable data for the complia nce demonstrations required under this subpart. (3) (i) For all newly-constructed affected EGUs und er this subpart that are also subject to the Acid Rain Prog ram, you must begin submitting the quarterly electronic emissions reports described in paragraph (c)(1) of this section in ac cordance with §75.64(a), i.e., beginning with data recorded on an d after the earlier of: (A) The date of provisional certification, as defin ed in §75.20(a)(3) of this chapter; or (B) 180 days after the date on which the EGU commen ces*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 822 of 854 commercial operation (as defined in §72.2 of this c hapter). (ii) For newly-constructed affected EGUs under this subpart that are not subject to the Acid Rain Program, you must begin submitting the quarterly electronic reports describ ed in paragraph (c)(2) of this section, beginning with da ta recorded

on and after: (A) The date on which reporting is required to begi n under §75.64(a), if that date occurs on or after the effe ctive date of this rule; or (B) The effective date of this rule, if the date o n which reporting would ordinarily be required to begin und er §75.64(a) has passed prior to the effective date of this rule

. (iii) For reconstructed or modified units, reportin g of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net electrical generation energy output data on that date. Otherwise, emissions data reporting shall begin on be on a gross energy output basis until the date that the Client Tool is first able to rec eive and process net generation energy output data. (4) If any required monitoring system has not been provisionally certified by the applicable date on w hich emissions data reporting is required to begin under paragraph*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 823 of 854 (c)(3) of this section, the maximum (or in some cas es, minimum) potential value for the parameter measured by the m onitoring system shall be reported until the required certifi cation testing is successfully completed, in accordance wi th §75.4(j) of this chapter, §75.37(b) of this chapter, or sect ion 2.4 of appendix D to part 75 of this chapter (as applicabl e). Operating hours in which CO 2 mass emission rates are calculated using maximum potential values are not “valid opera ting hours” (as defined in §60.5540(a)(1)), and shall not be us ed in the compliance determinations under §60.5540. (d) For affected EGUs subject to the Acid Rain Prog ram, the reports required under paragraphs (a) and (c)(1) of this section shall be submitted by: (1) The person appointed as the Designated Represen tative (DR) under §72.20 of this chapter; or (2) The person appointed as the Alternate Designate d Representative (ADR) under §72.22 of this chapter; or (3) A person (or persons) authorized by the DR or A DR under §72.26 of this chapter to make the required submiss ions. (e) For affected EGUs that are not subject to the A cid Rain Program, the owner or operator shall appoint a DR a nd (optional) an ADR to submit the reports required under paragra phs (a) and (c)(2) of this section. The DR and ADR must registe r with the*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 824 of 854 Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submiss ions to one

or more persons. ( e f ) If your affected EGU captures CO 2 to meet the applicable emission limit, you must report in accor dance with the requirements of 40 CFR Part 98 Subpart PP and e ither: (1) Report in accordance with the requirements of 4 0 CFR Part 98 subpart RR, if injection occurs on-site, or (2) Transfer the captured CO 2 to an EGU or facility that reports in accordance with the requirements of 40 C FR Part 98 subpart RR, if injection occurs off-site. § (3) Transfer the captured CO 2 to a facility that has received an innovative technology waiver from EPA pursuant t o paragraph (g) of this section. (g) Any person may request the Administrator to iss ue a waiver of the requirement that captured CO 2 from an affected EGU be transferred to a facility reporting under 40 CFR Part 98 subpart RR. To receive a waiver, the applicant mus t demonstrate to the Administrator that its technology will store captured CO 2 as effectively as geologic sequestration, and that the proposed technology will not cause or contribute to an unrea sonable risk to public health, welfare, or safety. In making th is determination, the Administrator shall consider (am ong other*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 825 of 854 factors) operating history of the technology, wheth er the technology will increase emissions or other release s of any pollutant other than CO 2 , and permanence of the CO 2 storage. The Administrator may test the system itself, or requir e the applicant to perform any tests considered by the Ad ministrator to be necessary to show the technology’s effectiven ess, safety, and ability to store captured CO 2 without release. The Administrator may grant conditional approval of a t echnology, the approval conditioned on monitoring and reportin g of operations. The Administrator may also withdraw ap proval of the waiver on evidence of releases of CO 2 or other pollutants. The Administrator will provide notice to the public of any application under this provision, and provide publi c notice of any proposed action on a petition before the Admini strator takes final action. § 60.5560 What records must I maintain? (a) You must maintain records of the information yo u used to demonstrate compliance with this subpart as spec ified in § 60.7 (b) and (f). (b) (1) For affected EGUs subject to the Acid Rain Program, you must follow the applicable recordkeeping requir ements and maintain records as required under subpart F of par t 75 of this chapter.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 826 of 854 (2) For affected EGUs that are not subject to the A cid Rain Program, you must also follow the recordkeeping req uirements and maintain records as required under subpart F of par t 75 of this chapter, to the extent that those records provide a pplicable data for the compliance determinations required und er this subpart. Regardless of the prior sentence, at a mi nimum, the following records must be kept, as applicable to th e types of continuous monitoring systems used to demonstrate c ompliance under this subpart: (i) Monitoring plan records under §75.53(g) and (h) of this chapter; (ii) Operating parameter records under §75.57(b)(1) through (b)(4) of this chapter; (iii) The records under §75.57(c)(2) of this chapte r, for stack gas volumetric flow rate; (iv) The records under §75.57(c)(3) for continuous moisture monitoring systems; (v) The records under §75.57(e)(1), except for para graph (e)(1)(x), for CO 2 concentration monitoring systems or O 2 monitors used to calculate CO 2 concentration; (vi) The records under §75.58(c)(1), paragraphs (c) (1)(i), (c)(1)(ii), and (c)(1)(viii) through (c)(1)(xiv), f or oil flow meters;*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 827 of 854 (vii) The records under §75.58(c)(4), paragraphs (c )(4)(i), (c)(4)(ii), (c)(4)(iv), (c)(4)(v), and (c)(4)(vii) through (c)(4)(xi), for gas flow meters; (viii) The quality-assurance records under §75.59(a ) of this chapter, paragraphs (a)(1) through (a)(12) and (a)(15), for CEMS; (ix) The quality-assurance records under §75.59(a) of this chapter, paragraphs (b)(1) through (b)(4), for fuel flow meters;

and (x) Records of data acquisition and handling system (DAHS) verification under §75.59(e) of this chapter. (c) You must keep records of the calculations you p erformed to determine the hourly and total CO 2 mass emissions (tons) for: (1) Each operating month (for all affected EGUs); (2) Each compliance period, including, each 12-oper ating

- month compliance period. (d) Consistent with § 60.5520, you must keep records of the applicable data recorded and calculations performed that you used to determine your affected EGU’s gross or net energy output for each operating month. (e) You must keep records of the calculations you p erformed to determine the percentage of valid CO 2 mass emission rates in each compliance period.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 828 of 854 (f) You must keep records of the calculations you p erformed to assess compliance with each applicable CO 2 mass emissions standard in Table 1 or 2 of this subpart. (g) You must keep records of the calculations you performed to determine any site-specific carbon-bas ed F-factors you used in the emissions calculations (if applicab le). § 60.5565 In what form and how long must I keep my re cords? (a) Your records must be in a form suitable and rea dily available for expeditious review. (b) You must maintain each record for 3 years after the date of conclusion of each compliance period. (c) You must maintain each record on site for at le ast 2 years after the date of each occurrence, measuremen t, maintenance, corrective action, report, or record, according to § 60.7. Records that are accessible from a central location by a computer or other means that instantly provide acce ss at the site meet this requirement. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart. Other Requirements and Information § 60.5570 What parts of the General Provisions apply to my affected EGU? Notwithstanding any other provision of this chapter ,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 829 of 854 certain parts of the General Provisions in § 60.1 through 60.19, listed in Table 3 to this subpart, do not apply to your affected

EGU. § 60.5575 Who implements and enforces this subpart? (a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, l ocal, or tribal agency. If the Administrator has delegated a uthority to your state, local, or tribal agency, then that agen cy (as well as the EPA) has the authority to implement and enfo rce this subpart. You should contact your EPA Regional Offic e to find out if this subpart is delegated to your state, local, or tribal

agency. (b) In delegating implementation and enforcement au thority of this subpart to a state, local, or tribal agency , the Administrator retains the authorities listed in par agraphs (b)(1) through (5) of this section and does not tra nsfer them to the state, local, or tribal agency. In addition, th e EPA retains oversight of this subpart and can take enforcement actions, as appropriate. (1) Approval of alternatives to the emission standa rds. (2) Approval of major alternatives to test methods. (3) Approval of major alternatives to monitoring. (4) Approval of major alternatives to recordkeeping and*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 830 of 854 reporting. (5) Performance test and data reduction waivers und er § 60.8(b). § 60.5580 What definitions apply to this subpart? As used in this subpart, all terms not defined here in will have the meaning given them in the Clean Air Act an d in subpart A (General Provisions of this part). Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,76 0 hours during a calendar year at the base load rating. Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state ba sis, as determined by the physical design and characteristi cs of the EGU at ISO conditions. For a stationary combustion turb ine,

baseload base load

rating includes the heat input from duct burners.

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the Americ an Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating usefu l heat, including but not limited to solvent-refined coal, gasified coal (not meeting the definition of natural gas), coal-o il mixtures,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 831 of 854 and coal-water mixtures are included in this defini tion for the purposes of this subpart.

Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay, and o ther organic and inorganic material. Combined cycle unit means an electric generating unit that

uses a stationary combustion turbine from which the heat f rom the turbine exhaust gases is recovered by a heat re covery steam generating unit (HRSG) to generate additional elect ricity. Combined heat and power unit or CHP unit, ( also known as “cogeneration”) means an electric generating unit that that use a steam-generating unit or stationary combustion tu rbine to simultaneously produce both electric (or mechanical ) and useful thermal output from the same primary energy source. Design efficiency means the rated overall net efficiency (e.g., electric plus useful thermal output) on a higher lower heating value basis of the EGU at the base load rating and , at ISO conditions

. , and at the maximum useful thermal output (e.g., C HP unit with condensing steam turbines would determine the design efficiency at the maximum level of extraction and/o r bypass). Design efficiency shall be determined using one of the following methods: ASME PTC 22 Gas Turbines (incorporated by reference,*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 832 of 854 see §60.17), ASME PTC 46 Overall Plant Performance (incorporated by reference, see §60.17) or ISO 2314:2009 Gas turb ines – acceptance tests (incorporated by reference, see §6 0.17). Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as def ined by the American Society of Testing and Materials in ASTM D 396 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Tes ting and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Tes ting and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Tes ting and Materials in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by the American Soci ety of Testing and Materials in ASTM D7467 (incorporated b y reference, see § 60.17). Electric Generating units or EGU means any steam generating unit, IGCC unit, or stationary combustion turbine t hat is subject to this rule (i.e., meets the applicability criteria) Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

Gaseous fuel means any fuel that is present as a gas at ISO*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 833 of 854 conditions and includes, but is not limited to, nat ural gas, refinery fuel gas, process gas, coke-oven gas, synt hetic gas, and gasified coal. Gross energy output means: (1) For stationary combustion turbines and IGCC, th e gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam t urbine(s), combustion turbine(s), and gas expander(s)) plus 10 0 percent of the useful thermal output. (2) For electric utility steam generating units, the gross electric or mechanical output from the affected EGU (s) (including, but not limited to, output from steam t urbine(s), combustion turbine(s), and gas expander(s)) minus a ny electricity used to power the feedwater pumps plus 100 percent of the useful thermal output; (3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consi sts of electric or direct mechanical output and 20.0 perce nt of the total gross energy output consists of useful therma l output on a

12- operaitng operating- month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), c ombustion turbine(s), and gas expander(s)) minus any electric ity used to*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 834 of 854 power the feedwater pumps (the electric auxiliary l oad of boiler feedwater pumps is not applicable to IGCC facilitie s), that difference divided by 0.95, plus 100 percent of the useful thermal output. Heat recovery steam generating unit (HRSG) means a an EGU in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Integrated gasification combined cycle unit or IGCC means a combined cycle stationary combustion turbine that i s designed to burn fuels containing 50 percent (by heat input) or more solidderived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid-derive d fuel requirement during periods of the gasification syst em construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the EGU during ope ration. ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure. Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual oil. Mechanical output means the useful mechanical energy that*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 835 of 854 is not used to operate the affected EGU(s), generat e electricity and/or thermal energy, or to enhance the performanc e of the affected EGU. Mechanical energy measured in horsepo wer hour should be converted into MWh by multiplying it by 7 45.7 then dividing by 1,000,000. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific val ue between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that mainta ins a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cub ic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke o ven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur CO 2 content or heating value. Net-electric sales means (1) The gross electric sales to the utility power distribution system minus purchased power; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consi sts of electric or direct mechanical output and at least 2 0.0 percent*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 836 of 854 of the total gross energy output consists of useful thermal output on an annual basis, the gross electric sales to the utility power distribution system minus purchased p ower of the thermal host EGU or facilities. (3) Electricity supplied to other facilities that p roduce electricity to offset auxiliary loads are included when calculating net-electric sales. (4) Electric sales that that result from a grid system emergency are not included when calculating net-ele ctric sales. Net-electric output means: the amount of gross generation the generator(s) produces (including, but not limit ed to, output from steam turbine(s), combustion turbine(s), and g as expander(s)), as measured at the generator terminal s, less the electricity used to operate the plant (i.e., auxili ary loads); such uses include fuel handling equipment, pumps, f ans, pollution control equipment, other electricity need s, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means: (i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output from the affected EGU plus 100 percent of the useful thermal output; or*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 837 of 854 (ii) For combined heat and power facilities where a t least 20.0 percent of the total gross or net energy outpu t consists of electric or direct mechanical output and at least 2 0.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating

- month rolling average basis, the net electric or mechanical output from the affe cted EGU divided by 0.95, plus 100 percent of the useful the rmal output; Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and re sidual oil, and gases derived from solid oil-derived fuels (not meeting the definition of natural gas). Operating month means a calendar month during which any fuel is combusted in the affected EGU at any time.

Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The e nthalpy of water at SATP conditions is 50 Btu/lb. Potential electric output means 33 percent or the base load rating design efficiency on a net output basis at the maximum electric production rate (e.g., CHP units w ith Formatted: Normal*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 838 of 854 condensing steam turbines will operate at maximum e lectric production), whichever is greater, multiplied by the base load rating (expressed in MMBtu/h) of the EGU, mult iplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1, 000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 p ercent efficient affected EGU with a 100 MW (341 MMBtu/h) fossil

fuel heat input capacity would have a 310,000 MWh 1 2 month potential electric output capacity). Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The e nthalpy of water at SATP conditions is 50 Btu/lb. Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under m oderate stress, and is not liquid or gaseous at ISO conditi ons. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, th e fuel, air, lubrication and exhaust gas systems, control system s (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post-combustion em ission control technology, and any ancillary components an d sub-*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 839 of 854 components comprising any simple cycle stationary c ombustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or u seful thermal output to the combustion turbine engine, heat recov ery system or auxiliary equipment. Stationary means that the comb ustion turbine is not self-propelled or intended to be pro pelled while performing its function. It may, however, be mounte d on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly it is considered a st eam generating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integra ted equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment. System emergency means any abnormal system condition that the Regional Transmission Organizations (RTO), Inde pendent System Operators (ISO) or control area Administrato r determines requires immediate automatic or manual action to pr event or limit loss of transmission facilities or generators that could adversely affect the reliability of the power syste m and therefore call for maximum generation resources to operate in*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 840 of 854 the affected area, or for the specific affected fac ility to operate to avert loss of load Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating ap plication, including thermal cooling applications) that is not used for electric generation, mechanical output at the affec ted EGU, to directly enhance the performance of the affected EG U (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered u seful thermal output), or to supply energy to a pollution control device at the affected EGU. Useful thermal output for affecte d EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in t he condensate (or other thermal energy input to the affected EGU( s)) would not meaningfully impact the emission rate calculation i s measured against the energy in the thermal output at SATP co nditions. Affected EGU(s) with meaningful energy in the conde nsate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that ener gy relative to SATP conditions from the measured thermal output

. System emergency

means any abnormal system condition that the Regional Transmission Organizations (RTO), Inde pendent*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 841 of 854 System Operators (ISO) or control area Administrato r determines requires immediate automatic or manual action to pr event or limit loss of transmission facilities or generators that could adversely affect the reliability of the power syste m and therefore call for maximum generation resources to operate in the affected area, or for the specific affected fac ility to operate to avert loss of load. Valid data means quality-assured data generated by continuous monitoring systems that are installed, o perated, and maintained according to part 75 of this chapter. For CEMS, the initial certification requirements in §75.20 of thi s chapter and appendix A to part 75 of this chapter must be met b efore quality-assured data are reported under this subpar t; for ongoing quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1 , 2.2, and 2.3 of appendix B to part 75 of this chapter must b e met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in s ection 2.1.5 of appendix D to part 75 of this chapter must be me t before quality-assured data are reported under this subpar t (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D), and for on-going quality assurance, th e provisions*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 842 of 854 in section 2.1.6 of appendix D to part 75 of this c hapter apply (except for qualifying commercial billing meters). Violation means a specified averaging period over which the

CO 2 emissions rate is higher than the applicable emissi ons standard located in Table 1 or Table 2 of this subp art.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 843 of 854 Table 1 of Subpart TTTT of Part 60 – CO 2 Emission Standards for Affected Steam Generating Units and Integrated Gasi fication Combined Cycle Facilities that Commenced Constructi on after January 8, 2014 and Reconstruction or Modification after June 18, 2014 (net energy output-based standards are only applica ble to affected EGUs subject to a federally enforceable pe rmit limiting GHG emissions on a net energy output basis) Note: all numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000

have a minimum of 2 significant figures Affected EGU CO 2 Emission Standard Newly constructed steam generating unit or integrated gasification combined cycle (IGCC) EGU 640 kg CO 2 /MWh of gross energy output (1,400 lb CO 2 /MWh)

Reconstructed steam generating unit or IGCC EGU that has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less 910 kg of CO 2 per MWh of gross energy output (2,000 lb CO 2 /MWh) Reconstructed steam generating unit or IGCC EGU that has a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h) 820 kg of CO 2 per MWh of gross energy output (1,800 lb CO 2 /MWh) Modified steam generating unit or IGCC unit A unit-specific emission limit determined by the unit’s best historical annual CO 2 emission rate (from 2002 to the date of the modification); the emission limit will be no lower than: 1. 1,800 lb CO 2 /MWh-gross for units with a base load rating greater than 2,000 MMBtu/h .; ; or 2. 2,000 lb CO 2 /MWh-gross for units with a base load rating of 2,000 MMBtu/h or less.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 844 of 854 Table 2 of Subpart TTTT of Part 60 – CO 2 Emission Standards for Affected Stationary Combustion Turbines that Commen ced Construction after January 8, 2014 and Reconstructi on or Modification after June 18, 2014 (net energy output-based standards applicable as approved by the Administrat or) Note: all numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000

have a minimum of 2 significant figures Affected EGU CO 2 Emission Standard 614 Newly constructed , or reconstructed , or modified stationary combustion turbine that supplies more than its design efficiency times its potential electric output as net-electric sales on a 3 year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operating-month rolling average basis. 450 kg of CO 2 per MWh of gross energy output (1,000 lb CO 2 /MWh); or 490 470 kilograms (kg) of CO 2 per megawatt-hour (MWh) of net energy output (1, 080 030 lb/MWh)

Newly constructed or reconstructed stationary combustion turbine that supplies its design efficiency times its potential electric output or less as net-electric sales on a 3 year rolling average basis and combusts more than 90% natural gas on a heatinput basis on a 12-operatingmonth rolling average basis. 50 kg CO 2 per gigajoule (GJ) of heat input (120 lb CO 2 /MMBtu)

Newly constructed and reconstructed stationary combustion turbine that combusts 90% or less natural gas on a heat input basis on a 12-operating-month rolling average basis. 50 kg CO 2 /GJ of heat input (120 lb/MMBtu) to 69 kg CO 2 /GJ of heat input (160 lb/MMBtu) as determined by the procedures in § 60.5525

614 See procedures for establishing and revising the co mpliance option under § 60.5520.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 845 of 854 Table 3 to Subpart TTTT of Part 60 – Applicability of Subpart A General Provisions to Subpart TTTT General Provisions citation Subject of

citation Applies to subpart TTTT Explanation § 60.1 Applicability Yes § 60.2 Definitions Yes Additional terms defined in § 60.5580 § 60.3 Units and

Abbreviations Yes

§ 60.4 Address Yes Does not apply to information reported electronically through ECMPS. Duplicate submittals are not required. § 60.5 Determination of

construction or modification Yes § 60.6 Review of plans Yes

§ 60.7 Notification and

Recordkeeping Yes Only the requirements to submit the notifications in 60.7(a)(1) and (a)(3) and to keep records of malfunctions in §60.7(b), if applicable § 60.8 Performance tests No § 60.9 Availability of

Information Yes § 60.10 State authority Yes

§ 60.11 Compliance with

standards and maintenance requirements No

§ 60.12 Circumvention Yes § 60.13 Monitoring

requirements No All monitoring is done according to Part 75*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 846 of 854

§ 60.14 Modification No § 60.15 Reconstruction No § 60.16 Priority list No § 60.17 Incorporations by

reference Yes

§ 60.18 General control

device requirements No

§ 60.19 General

notification and reporting requirements Yes Does not apply to notifications under §75.61 or to information reported through ECMPS.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 847 of 854 PART 70— STATE OPERATING PERMIT PROGRAMS

3 4 . The authority citation for part 70 continues to r ead as

follows: Authority : 42 U.S.C. 7401 et seq.

4 5 . Section 70.2 is amended by revising the introduct ory text, removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph ( 4) to the definition of “Regulated pollutant (for presumptive fee calculation).” The revision and additions read as follows: § 70.2 Definitions.

* * * * * Regulated pollutant (for presumptive fee calculatio n) , which is used only for purposes of § 70.9(b)(2), means any regulated air pollutant except the following:

* * * * * (4) Greenhouse gases.

* * * * *

5 6 . Section 70.9 is amended by revising paragraph (b) (2)(i), and by adding paragraph (b)(2)(v) to read as follow s: § 70.9 Fee determination and certification.

* * * * **** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 848 of 854 (b) * * * (2)(i) The Administrator will presume that the fee schedule meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] time s the total tons of the actual emissions of each regulated poll utant (for presumptive fee calculation) emitted from part 70 s ources and any GHG cost adjustment required under paragraph (b )(2)(v) of this section.

* * * * * (v) GHG cost adjustment . The amount calculated in paragraph (b)(2)(i) of this section shall be increased by the GHG cost adjustment determined as follows: For each activit y identified in the following table, multiply the number of acti vities performed by the permitting authority by the burden hours per activity, and then calculate a total number of burd en hours for all activities. Next, multiply the burden hours by the average cost of staff time, including wages, employee benef its and

overhead.

Activity Burden hours per activity GHG completeness determination (for initial permit or updated application) 43*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 849 of 854

GHG evaluation for a permit modification or related permit action GHG evaluation at permit renewal 7 10 * * * * * PART 71— FEDERAL OPERATING PERMIT PROGRAMS

6 7 . The authority citation for part 71 continues to r ead as

follows: Authority : 42 U.S.C. 7401 et seq.

7 8 . Section 71.2 is amended by removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulate d pollutant (for fee calculation).” The revisions and additions read as follows: § 71.2 Definitions.

* * * * * Regulated pollutant (for fee calculation), which is used only for purposes of § 71.9(c), means any “ regulated air pollutant ” except the following:

* * * * * (4) Greenhouse gases.

* * * * *

8 9 . Section 71.9 is amended by: a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), a nd (c)(4), and b. Adding paragraph (c)(8).*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 850 of 854 The revisions and additions read as follows: § 71.9 Permit fees.

* * * * * (c) * * * (1) For part 71 programs that are administered by E PA, each part 71 source shall pay an annual fee which is the sum of: (i) $32 per ton (as adjusted pursuant to the criter ia set forth in paragraph (n)(1) of this section) times th e total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fug itive emissions; and (ii) Any GHG fee adjustment required under paragrap h (c)(8) of this section. (2) * * * (i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph (c)(2)(ii) of this section, the annual fee for each part 71 source shall be the sum of: (A) $24 per ton (as adjusted pursuant to the criter ia set forth in paragraph (n)(1) of this section) times th e total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fug itive emissions; and*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 851 of 854 (B) Any GHG fee adjustment required under paragraph (c)(8) of this section.

* * * * * (3) For part 71 programs that are administered by E PA with contractor assistance, the per ton fee shall vary d epending on the extent of contractor involvement and the cost t o EPA of contractor assistance. The EPA shall establish a pe r ton fee that is based on the contractor costs for the speci fic part 71 program that is being administered, using the follo wing

formula: Cost per ton=( E

×32)+[(1 − E

)×$ C ]

Where E

represents EPA's proportion of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1- E represents the contractor's effort,

and C represents the contractor assistance cost on a per ton basis. C

shall be computed by using the following formula:

C =[ B + T + N ] divided by 12,300,000

Where B represents the base cost (contractor costs), where

T represents travel costs, and where N represents nonpersonnel data management and tracking costs. In addition, each part 71 source shall pay a GHG fee adjustment for each acti vity as required under paragraph (c)(8) of this section.*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 852 of 854 (4) For programs that are delegated in part, the fe e shall be computed using the following formula: Cost per ton=( E

×32)+( D ×24)+[(1 − E − D )×$ C ]

Where E

and D represent, respectively, the EPA and delegate agency proportions of total effort (expressed as a percentage of total effort) needed to administer the part 71 prog ram, 1 − E − D represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed using the formula for contractor assistanc e cost found in paragraph (c)(3) of this section and shall be ze ro if contractor assistance is not utilized. In addition , each part 71 source shall pay a GHG fee adjustment for each a ctivity as required under paragraph (c)(8) of this section.

* * * * * (8) GHG fee adjustment . The annual fee shall be increased by a GHG fee adjustment for any source that has ini tiated an activity listed in the following table since the fe e was last paid. The GHG fee adjustment shall be equal to the set fee provided in the table for each activity that has be en initiated since the fee was last paid:

Activity Set fee*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 853 of 854 GHG completeness determination (for initial permit or updated application) GHG evaluation for a permit modification or related permit action GHG evaluation at permit renewal $2,236

$364 $520 * * * * * PART 98— MANDATORY GREENHOUSE GAS REPORTING

9 10 . The authority citation for part 98 is revised to read

as follows: Authority: 42 U.S.C. 7401-7671q. Subpart PP—Suppliers of Carbon Dioxide

10 11 . Section 98.426 is amended by adding paragraph (h) to read as follows: § 98.426 Data reporting requirements.

* * * * * (h) If you capture a CO 2 stream from an electricity generating unit that is subject to subpart D of thi s part and

transfer CO 2 to any facilities that are subject to subpart RR o f this part, you must: (1) Report the facility identification number assoc iated with the annual GHG report for the subpart D facili ty, (2) Report each facility identification number asso ciated with the annual GHG reports for each subpart RR fac ility to which CO 2 is transferred, and*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review *** Page 854 of 854 (3) Report the annual quantity of CO 2 in metric tons that is transferred to each subpart RR facility. 11. Section 98.427 is amended by adding paragraph ( d) to

read as follows: § 98.427 Records that must be retained.

* * * * * (d) Facilities subject to § 98.426(h) must retain records of

CO 2 in metric tons that is transferred to each subpart RR facility.

Formatted: Line spacing: Double