*** EO 12866 Review - Draft – Do Not Cite, Quote or Release During Review ***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-99 30-66-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). Thi s 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 In a separ ate action, under CAA section 111(d), the EPA is issuing final emission***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 2 of 786 guidelines for states to use in developing plans to limit CO 2 emissions from existing fossil fuel-fired EGUs.

DATES: This final rule is effective on [ insert date 60 days after date of publication in the Federal Register ]. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Reg ister 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 3 of 786 holidays. The telephone number for the Public Readi ng Room is (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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 4 of 786

CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration) 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 5 of 786 MW Megawatt MWe Megawatt Electrical 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 6 of 786

UMRA Unfunded Mandates Reform Act of 1995 U.S. United States 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 Fossi l Fuelfired Electric Utility Generating Units G. Stakeholder Engagement and Public Comments on the P roposals III. Regulatory Authority, Affected EGUs 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-based 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 7 of 786 V. Rationale for Final Standards for Newly Construc ted Fossil Fuel-fired Electric Utility Steam Generating Units 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 Carbon Capture E. Pre-Combustion Carbon Capture F. Vendor Guarantees, Industry Statements, Academic Li terature, and Commercial Availability G. Response to Key Comments on the Adequacy of the Tec hnical Feasibility Demonstration H. Consideration of Costs I. Key Comments Regarding the EPA’s Consideration of Costs J. Achievability of the Final Standards K. Emission Reductions Utilizing Partial CCS L. Further Development and Deployment of CCS Technolog y M. Technical and Geographic Aspects of Disposition of Captured CO 2 N. Final Requirements for Disposition of Captured CO 2 O. NonairNon-air Quality Impacts and Energy Requirements 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 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 and Reconstructed Stationary Combustion Turbines A. Applicability B. Subcategories C. Identification of the Best System of Emission Reduc tion***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 8 of 786

D. Achievability of the Final Standards 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 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 Thi s Rule 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 XIII. 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? XIV. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 9 of 786

J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and L ow-Income Populations K. Congressional Review Act (CRA) XV. Withdrawal of Proposed Standards for Certain Mo dified Sources XVI. Statutory Authority I. General Information A. Executive Summary 1. Purpose of the Regulatory Action In this final action the EPA is establishing standa rds that limit greenhouse gas (GHG) emissions from newly con structed, modified, and reconstructed fossil fuel-fired elect ric utility steam generating units and stationary combustion tu rbines, following the issuance of proposals for such standa rds 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 , the EPA issued proposed carbon pollution standards for newl y constructed fossil fuel-fired power plants. The proposal was pu blished in

the Federal Register on January 8, 2014 (79 FR 1430; “January***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 10 of 786 2014 proposal”). 1 In that proposal, the EPA proposed to limit

emissions of CO 2 from newly constructed fossil fuel-fired electric utility steam generating units and newly c onstructed 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, the EPA proposed standards of perf ormance, also pursuant to CAA section 111(b), to limit emiss ions of CO 2 from modified and reconstructed fossil fuel-fired e lectric utility steam generating units and natural gas-fire d stationary combustion turbines. 79 FR 34960 (June 18, 2014) (“ June 2014 proposal”). Specifically, the EPA proposed standard s of performance for: (1) modified fossil fuel-fired ste am generating units, (2) modified natural gas-fired stationary co mbustion

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 786 turbines, (3) reconstructed fossil fuel-fired steam generating units, and (4) reconstructed natural gas-fired stat ionary

combustion turbines. In this action, the EPA is issuing final standards of performance to limit emissions of GHG pollution man ifested as CO 2 from newly constructed, modified, and reconstructed fossil fuelfired electric utility steam generating units (i.e. , utility boilers and integrated gasification combined cycle (IGCC) units) and from newly constructed and reconstructed statio nary combustion turbines. Consistent with the requiremen ts of CAA section 111(b), these standards reflect the degree of emission 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-fire d EGUs. In a separate action that affects the same source c ategory, the EPA is issuing final emission guidelines under CAA section 111(d) for states to use in developing plans to lim it CO 2 emissions from existing fossil fuel-fired EGUs. Pur suant to those guidelines, states must submit plans to the E PA following a schedule set by the guidelines.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 12 of 786

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 certain changes from the proposals. Comment s considered include written comments that were submitted during the public comment period and oral testimony provided during t he 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

final standards for modified and reconstructed foss il fuel-fired EGUs apply to those sources that modify or reconstr uct on or

2 See CAA section 111(a)(2).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 13 of 786 after the date of publication of the proposed stand ards, June 18, 2014. Table 1. Summary of BSER and Final Standards for Af fected EGUs

Affected EGUs BSER Final Standard s of Performance

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

Modified Fossil Fuel-Fired Steam Generating Units Most efficient generation at the affected EGU achievable through a combination of best operating practices and equipment upgrades Sources making modifications resulting in an increase in 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 more stringent than: 1. 1,800 lb CO 2 /MWh-g for sources with heat input > 2,000 MMBtu/h. OR 2. 2,000 lb CO 2 /MWh-g for sources with heat***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 14 of 786 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 /MWh-g. 2. Sources with heat input ≤ 2,000 MMBtu/h are required to meet an emission limit of 2,000 lb CO 2 /MWh-g.

Newly Constructed 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 /MWh-g or 1,030 lb CO 2 /MWh-n for base load natural gas-fired units. 2. 120 lb CO 2 /MMBtu for non-base load natural gas-fired units. 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-operating - month 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 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 15 of 786

a. Fossil fuel-fired electric utility steam generat ing units This action establishes standards of performance f or newly constructed fossil fuel-fired steam generating unit s 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 a wide range of com ments, technical input received on the availability, techn ical feasibility, and cost of CCS implementation, and pu blicly available information about projects that are imple menting or planning to implement CCS, the EPA confirms its pro posed determination that CCS technology is available and technically feasible to implement at fossil fuel-fired steam ge nerating units. However, the EPA’s final standard reflects t he consideration of legitimate concerns regarding the cost to implement available CCS technology on a new steam g enerating unit. Accordingly, the EPA is finalizing an emissio n standard for newly constructed fossil fuel-fired steam gener ating units at 1,400 lb CO 2 /MWh-g, a level that is less stringent than the proposed limitation of 1,100 lb CO 2 /MWh-g. This final standard

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 786

reflects our identification of the BSER for such un its to be a lower level of partial CCS than we identified as th e basis of the proposed standards – one that we conclude bette r represents the requirement that the BSER be implementable at r easonable

cost. The EPA proposed that the BSER for newly constructe d steam generating EGUs was highly efficient new generating technology (i.e., a supercritical utility boiler or IGCC unit) implementing partial CCS technology to achieve 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 final action, the EPA finds that a highly e fficient new supercritical pulverized coal (SCPC) utility boiler 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 – either with natural gas co-firing or implementing p artial CCS – is not part of the BSER, but recognizes that IGCC t echnology can serve as an alternative method of compliance.

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 786 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, includi ng the power generation sector. For example, the Boundary Dam Un it #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. A newly constructed, highly e fficient SCPC utility boiler burning bituminous coal will be able to meet this final standard of performance by capturing and stor ing approximately 16 percent of the CO 2 produced from the facility. A newly constructed, highly efficient SCPC utility bo iler burning subbituminous coal or dried lignite 7 will be able to meet this final standard of performance by capturing and stor ing approximately 23 percent of the CO 2 produced from the facility. As an alternative compliance option, utilities and project developers will also be able to construct new steam generating units (both utility boilers and IGCC units) that me et the final

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 18 of 786 standard of performance by co-firing with natural g as. This final standard of performance for newly constructed fossil fuelfired steam generating units provides a clear and a chievable path forward for the construction of such sources w hile addressing GHG emissions and supporting technologic al innovation. The standard of 1,400 lb CO 2 /MWh-g is achievable by fossil fuel-fired steam generating units for all fu el types, under a wide range of conditions, and throughout th e United

States. We note that identifying a highly efficient new SCP C EGU implementing partial CCS as the BSER provides a pat h forward for new fossil fuel-fired steam generation in the curre nt market context. Numerous studies have predicted that few n ew fossil fuel-fired steam generating units will be construct ed in the future. These analyses identify a range of factors unrelated to this rulemaking, including low electricity demand g rowth, highly competitive natural gas prices, and increases in th e supply of renewable energy. The EPA recognizes that, in certa in circumstances, there may be interest in building fo ssil fuelfired steam generating units despite these market c onditions. In particular, utilities and project developers may bu ild new fossil fuel-fired steam generating EGUs in order to achieve or maintain fuel diversity within generating fleets, a s a hedge against the possibility of natural gas prices far e xceeding***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 19 of 786 projections, or to co-produce both power and chemic als, including capturing CO 2 for use in enhanced oil recovery (EOR) projects. 8 As regulatory history has shown, identifying a new highly efficient SCPC EGU implementing partial CCS as the BSER in this rule is likely to further boost research an d development in CCS technologies, making the implementation even more efficacious and cost-effective, while providing a c ompetitive, low emission future for fossil fuel-fired steam gen eration. The EPA is also issuing final standards for steam generating units that implement “large modification s,” (i.e., modifications resulting in an increase in hourly CO 2 emissions of more than 10 percent when compared to the source’s highest

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 electricity sector, these concepts are not included in LCOE or LACE calculations. http://www.eia.gov/forecasts/aeo/electricity_genera tion.cfm***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 20 of 786 hourly emissions in the previous 5 years). 9 The EPA is not issuing final standards, at this time, for steam ge nerating units that implement “small modifications” (i.e., m odifications resulting in an increase in hourly CO 2 emissions of less than or equal to 10 percent when compared to the source’s h ighest hourly emissions in the previous 5 years). The standards of performance for modified steam gen erating units that make large modifications are based on ea ch affected unit’s own best potential performance as the BSER. Specifically, such a modified steam generating unit will be requi red to meet a unit-specific CO 2 emission limit determined by that unit's best demonstrated historical performance (in the years f rom 2002 to the time of the modification). 10 The EPA has determined that this standard based on each unit’s own best potential pe rformance can be met through a combination of best operating prac tices and equipment upgrades and that these steps can be impl emented costeffectively at the time when a source is undertakin g a large

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.” 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 21 of 786

modification. To account for facilities that have a lready implemented best practices and equipment upgrades, the final rule also specifies that modified facilities will n ot have to meet an emission standard more stringent than the c orresponding standard for reconstructed steam generating units ( i.e., 1,800

lb CO 2 /MWh-g for units with heat input greater than 2,000 MMBtu/h and 2,000 lb CO 2 /MWh-g for units with heat input less than or equal to 2,000 MMBtu/h). 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 steam generating sources that make modifications resultin g in an***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 22 of 786 increase of hourly CO 2 emissions of less than or equal to 10 percent (see Section XV of this preamble). As we in dicated in the proposal, the EPA has been notified 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 fo r GHG emissions as well. Even so, we also recognize (and we discuss in this preamble) that the power sector is undergoing significant 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 c hanges. In particular, we do not have sufficient information a bout the types of modifications, if any, that would result i n 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 based on the performance of th e 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 b oiler was not***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 23 of 786 originally designed to do so). 11 The emission standard for these sources is 1,800 lb CO 2 /MWh-g for large sources, (i.e. those with a heat input rating of greater than 2,000 MMBtu/h) or 2,000 lb

CO 2 /MWh-g for small sources (i.e., those with a heat i nput rating of 2,000 MMBtu/h or less). The difference in the st andards for larger and smaller units is based on greater availa bility of higher pressure/temperature steam turbines (e.g., s upercritical steam turbines) for larger units. The standards can also be met through other non-BSER options, such as natural gas co-firing. b. Stationary combustion turbines This action also finalizes standards of performance for newly constructed and reconstructed stationary comb ustion turbines. In the January 2014 proposal for newly co nstructed EGUs, the EPA proposed that natural gas-fired stati onary combustion turbines (i.e., turbines combusting over 90 percent natural gas) would be subject to a standard of perf ormance for

CO 2 emissions if they are constructed for the purpose of supplying and actually annually supply to the grid (1) one-third or more of their potential electric output 12 and (2) more than

11 Steam with higher temperature and pressure has mor e thermal energy that can be more efficiently converted to el ectrical energy. 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."***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 24 of 786 219,000 MWh, 13 based on a three-year rolling average. We refer to units that operate above the electric sales thresho lds as "base load units," and we refer to units that operate bel ow these

thresholds as "non-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 reconstr ucted combustion turbines, the EPA solicited comment on a lternative approaches for establishing applicability and subca tegorization criteria, including (1) eliminating the “constructe d for the purpose of supplying” qualifier for the total elect ric sales and percentage electric sales criteria, (2) eliminating the 219,000 MWh total electric sales criterion altogether, (3) replacing the fixed percentage electric sales criterion with a va riable

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 786 percentage electric sales criterion (i.e., the slid ing-scale approach 14 ), and (4) eliminating the proposed small and large subcategories for base load natural gas-fired combu stion turbines. These proposed applicability requirements were intended to exclude combustion turbines that are us ed for the purpose of meeting peak power demand, as opposed to those that are used to meet 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 approaches put forward in the January 2014 proposal for new sources and the June 2014 proposal for modified and reconstructed sources. Based on our review of publi c comments related to the proposed subcategories for small and large

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 26 of 786 combustion turbines and our additional data analyse s, we have determined that there is no need to set two separat e standards

for different size combustion turbines for base loa d natural gas-fired combustion turbines. The EPA has determin ed that all sizes of affected newly constructed and reconstruct ed stationary

combustion turbines can achieve the final standards . For newly constructed and reconstructed base load natural gas -fired stationary combustion turbines, the EPA is finalizi ng a standard of 1,000 lb CO 2 /MWh-g based on efficient natural gas combined cycled (NGCC) technology as the BSER. Alternatively , owners and operators of base load natural gas-fired combustion turbines may elect to comply with a standard based on net output of 1,030 lb

CO 2 /MWh-n. The EPA is eliminating the 219,000 MWh total annual

electric sales criterion for non-CHP units. In addi tion, the EPA is finalizing the sliding-scale approach for derivi ng the unitspecific, percentage electric sales threshold above which a combustion turbine transitions from the subcategory for non-base load units to the subcategory for base load units. For newly

constructed and reconstructed non-base load natural gas-fired stationary combustion turbines, the EPA is finalizi ng the combustion of clean fuels (natural gas with a small allowance for distillate oil) as the BSER with a correspondin g heat inputbased standard of 120 lb CO 2 /MMBtu. This standard of performance***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 27 of 786 will apply to the vast majority of simple cycle com bustion turbines. The EPA is finalizing a heat input-based clean fuels

standard because we have insufficient information a t this time to set a uniform output-based standard that can be achieved by

all new and reconstructed non-base load units. 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. 15 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. 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

15 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 28 of 786 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) 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 29 of 786 likely to be NGCC and that any coal-fired steam gen erating units built between now and 2030 would have CCS, even in the absence

of this rule. 16 Therefore, based on the analysis presented in Chapter 4 of the RIA, the EPA projects that this fi nal rule will result in negligible CO 2 emission changes, quantified benefits, and costs by 2022 as a result of the performance st andards for newly constructed EGUs. 17 However, as noted earlier, for a variety of reasons, some companies may consider coa l-fired steam generating units that the modeling does not anticip ate. Thus, in Chapter 5 of the RIA, we also present an analysis o f the project-level costs of a newly constructed coal-fir ed steam generating unit with partial CCS that meets the req uirements of this final rule alongside the project-level costs o f a newly

constructed coal-fired unit without CCS. This analysis indicates that the quantified benefits of the standards of pe rformance would exceed their costs under a range of assumptio ns. As explained in the RIA and further below, the EPA has been notified of few power sector NSPS modifications or

16 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). 17 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 30 of 786 reconstructions. Based on that experience, the EPA expects that few EGUs will trigger either the modification or th e reconstruction provisions that we are finalizing in this action. 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.

B. Does this Action Applyaction apply to Meme ? 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

Industry 221112 Fossil fuel electric power generati ng 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 31 of 786 This table is not intended to be exhaustive, but ra ther 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 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 Cancan I Getget a Copycopy of this Documentdocument ? 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 the Federa l***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 32 of 786 Register ]. Moreover, under section 307(b)(2) of the CAA, th e requirements established by this final rule may not be challenged separately in any civil or criminal proc eedings brought by the EPA to enforce these requirements. Section 307(d)(7)(B) of the CAA further provides that “[o]n ly an 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 man dating the EPA to convene a proceeding for reconsideration “[i ]f the person raising an objection can demonstrate to the EPA tha t it was impracticable to raise such objection within [the p eriod 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 should submit a Petition for Reconsid eration to the Office of the Administrator, U.S. EPA, Room 300 0, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the person(s) listed in the pre ceding FOR

FURTHER INFORMATION CONTACT section, and the Associate General Counsel for the Air and Radiation Law Office, Offic e of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylva nia Ave., NW, Washington, DC 20460.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 33 of 786

E. How is this Preamble Organizedpreamble 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 newly constructed and reconstructed stationary comb ustion turbines. Section II provides background informatio n on climate change impacts from GHG emissions, GHG emissions fr om fossil fuel-fired EGUs, the utility power sector, the stat utory and regulatory background relating to CAA section 111(b ), EPA actions prior to this final action, and public comm ents regarding the proposed actions. Section III explain s the EPA’s authority to regulate CO 2 and EGUs, identifies affected EGUs, and describes the source categories. Section IV provide s a summary of the final standards for newly constructed, modif ied, and reconstructed fossil fuel-fired steam generating un its. Sections V through VII present the rationale for the final s tandards for newly constructed, modified, and reconstructed stea m generating units, respectively. Sections VIII and IX provide a summary of the final standards for stationary combustion turbi nes and present the rationale for the final standards for n ewly constructed and reconstructed combustion turbines, respectively. Section X provides a summary of other final require ments for newly constructed, modified, and reconstructed foss il fuel-fired steam generating units and stationary combustion tu rbines.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 34 of 786 Section XI addresses the consistency of the respect ive BSER

determinations in these rules and under the emissio n guidelines issued separately under CAA section 111(d). Interac tions with other EPA programs and rules are described in Secti on XII. Projected impacts of the final action are then desc ribed in Section XIII, followed by a discussion of statutory and

executive order reviews in Section XIV. Section XV addresses the withdrawal of the proposed standards for steam gene rating EGUs that make modifications resulting in an increase of hourly CO 2 emissions of less than or equal to 10 percent and t he proposed standards for modified stationary combustion turbin es. The statutory authority for this action is provided in Section XVI. We address major comments throughout this preamble and in greater detail in an accompanying response-to-comme nts 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 and describe the utility power sector and its changing structure. We then summarize the statutory and regu latory background relevant to this final rulemaking. In ad dition, we provide background information on the EPA’s January 8, 2014 proposed carbon pollution standards for newly const ructed fossil***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 35 of 786 fuel-fired EGUs, the June 18, 2014 proposed carbon pollution standards for modified and reconstructed EGUs, and other actions associated with this final rulemaking. We close thi s section with a general discussion of comments and stakehold er input that the EPA received prior to issuing this final rulema king. 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.” 18 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). 19 In the Endangerment Finding, the Administrator found that the current, elevated concentrations of GHGs in the atmosphere — already at

18 National Research Council, Climate Stabilization T argets, p. 3. 19 “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 36 of 786 levels unprecedented in human history — may reasona bly be anticipated to endanger public health and welfare o f current and 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., especially 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 37 of 786 disorders. Children, the elderly, and the poor are among the

most vulnerable to these climate-related health eff ects. 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, erosion, 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 38 of 786 balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards in creasing 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 39 of 786

United States (NCA3), and the NRC’s 2010 Ocean Acidification: A National Strategy to Meet the Challenges of a Chang ing Ocean (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 III.A of the 2009 Endangerment Finding, which was to rely primar ily upon the major assessments by the USGCRP, the IPCC, and the NRC of the National Academies to provide the technical and sci entific 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 40 of 786 exacting peer review by the expert community, as we ll as rigorous levels of U.S. government review. 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)***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 41 of 786 have significant impacts, observed now and projecte d, on the health and well-being of Arctic residents, especial ly indigenous 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.” 20 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

20 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 42 of 786

floods. The IPCC finds that additional health conce rns may arise in low-income households, especially those with chi ldren, if 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. 21 In fact, that assessment stated that “the magnitude and rate of the present greenhouse g as increase

21 National Research Council, Understanding Earth’s D eep Past, p. 1.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 43 of 786 place the climate system in what could be one of th e most severe increases in radiative forcing of the global climat e system in Earth history.” 22 Because of these unprecedented changes, several assessments state that we may be approaching critic al, poorly understood thresholds. As stated in the assessment, “As Earth continues to warm, it may be approaching a critical climate threshold beyond which rapid and potentially perman ent — at least on a human timescale — changes not anticipate d by climate models tuned to modern conditions may occur.” The N RC Abrupt Impacts report analyzed abrupt climate change in the physi cal climate system and abrupt impacts of ongoing change s that, when thresholds are crossed, can cause abrupt impacts fo r society and ecosystems. The report considered destabilization o f the West Antarctic Ice Sheet (which could cause 3-4 m of pot ential sea level rise) as an abrupt climate impact with unknow n but probably low probability of occurring this century. The report categorized a decrease in ocean oxygen content (wit h attendant threats to aerobic marine life); increase in intens ity, frequency, and duration of heat waves; and increase in frequency and intensity of extreme precipitation events (drou ghts, floods, hurricanes, and major storms) as climate impacts wi th moderate risk of an abrupt change within this century. The N RC Abrupt

22 Id., p. 138.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 44 of 786 Impacts report also analyzed the threat of rapid state chan ges in ecosystems and species extinctions as examples o f irreversible impacts that are expected to be exacer bated by climate change. Species at most risk include those whose migration potential is limited, whether because the y live on mountaintops or fragmented habitats with barriers t o movement, or because climatic conditions are changing more ra pidly than the species can move or adapt. While the NRC determ ined that it is not presently possible to place exact probabilit ies on the added contribution of climate change to extinction, they did find that there was substantial risk that impacts f rom climate change could, within a few decades, drop the popula tions in many species below sustainable levels, thereby committin g the species to extinction. Species within tropical and subtropi cal rainforests such as the Amazon and species living i n coral reef ecosystems were identified by the NRC as being part icularly vulnerable to extinction over the next 30 to 80 yea rs, as were species in high latitude and high elevation regions . Moreover, due to the time lags inherent in the Earth’s climat e, the NRC Climate Stabilization Targets assessment notes that the full warming from any given concentration of CO 2 reached will not be fully realized for several centuries, underscoring that emission activities today carry with them climate commitment s far into

the future.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 45 of 786 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 th e 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 impact 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 western 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 experiencing its driest period in 800 years. Simila rly, the NCA3 projects that heavy downpours are expected to incre ase in many***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 46 of 786 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 CO 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 Implications assessment suggests that “the Department of the Navy should expect roughly 0.4 to 2 meters (1.3 to 6.6 feet)***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 47 of 786 global average sea-level rise by 2100,” 23 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 east coast of the U.S. in particular is expected to see higher ra tes of sea level rise than the global average. For comparison, the NCA3

states that “five million Americans and hundreds of billions of dollars of property are located in areas that are l ess than four feet above the local high-tide level,” and the NCA3 finds that “[c]oastal infrastructure, including roads, rail li nes, energy infrastructure, airports, port facilities, and mili tary bases, are increasingly at risk from sea level rise and da maging storm surges.” 24 Also, because of the inertia of the oceans, sea le vel

rise will continue for centuries after GHG concentr ations have stabilized (though more slowly than it would have o therwise). Additionally, there is a threshold temperature abov e which the

Greenland ice sheet will be committed to inevitable melting.

23 NRC, 2011: National Security Implications of Climate Change for U.S. Naval Forces . The National Academies Press, p. 28. 24 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 48 of 786 According to the NCA, some recent research has sugg ested that even present day CO 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 tha t 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 U.S. Particularly in Alask a, critical

infrastructure and traditional livelihoods are thre atened by climate change and, “[i]n parts of Alaska, Louisian a, the Pacific Islands, and other coastal locations, clima te change impacts (through erosion and inundation) are so sev ere that some communities are already relocating from historical homelands to

which their traditions and cultural identities are tied.” 25 The IPCC AR5 notes, “Climate-related hazards exacerbate other stressors, often with negative outcomes for livelih oods, especially for people living in poverty (high confi dence).

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. 17.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 49 of 786 Climate-related hazards affect poor people’s lives directly through impacts on livelihoods, reductions in crop yields, or destruction of homes and indirectly through, for ex ample, increased food prices and food insecurity.” 26

CO 2 in particular has unique impacts on ocean ecosyste ms.

The NRC Climate Stabilization Targets assessment found that coral bleaching will increase due both to warming a nd ocean acidification. Ocean surface waters have already be come 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 past 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 Impacts assessment specifically highlighted similarities b etween the projections for future acidification and warmin g and the

26 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 50 of 786

extinction at the end of the Permian which resulted in the loss of an estimated 90 percent of known species. Simila rly, the NRC

Ocean Acidification assessment finds that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic CO 2 emissions; the rate of change exceeds any known to have occurred for at least the past hundre ds of thousands of years.” 27 The assessment notes that the full range of consequences is still unknown, but the risks “th reaten coral reefs, fisheries, protected species, and other natu ral resources of value to society.” 28 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 humanitarian aid; responding to the effects of clim ate change in geopolitical hotspots, including possible mass migr ations; and

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

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 51 of 786 addressing changing security needs in the Arctic 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 perio d of the last 1400 years. U.S. average temperatures have similarl y increased by 1.3 to 1.9 °F since 1895, with most of that incr ease occurring since 1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 2010. Contributing to this rise was th e warming of the oceans and melting of land ice. It is likely th at 275 gigatons per year of ice have melted from land glac iers (not including ice sheets) since 1993, and that the rate of loss of

ice from the Greenland and Antarctic ice sheets has increased substantially in recent years, to 215 gigatons per year and 147***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 52 of 786 gigatons per year respectively, since 2002. For con text, 360 gigatons of ice melt is sufficient to cause global sea levels to

rise 1 mm. Annual mean Arctic sea ice has been decl ining at 3.5 to 4.1 percent per decade, and Northern Hemisphere snow cover extent has decreased at about 1.6 percent per decad e for March and 11.7 percent per decade for June. Permafrost te mperatures have increased in most regions since the 1980s, by up to 3 °C (5.4 °F) in parts of Northern Alaska. Winter storm frequency and intensity have both increased in the Northern Hemis phere. The NCA3 states that the increases in the severity or f requency of some types of extreme weather and climate events in recent decades can affect energy production and delivery, causing supply disruptions, and compromise other essential infrastructure such as water and transportation sys tems. 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. 29 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

29 ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_an nmean_mlo.txt***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 53 of 786 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 based on ice core

records. 30 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. 31 And 2014 was the warmest year globally in the 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. 32 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

30 http://www.esrl.noaa.gov/gmd/ccgg/trends/. 31 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238. 32 http://www.ncdc.noaa.gov/sotc/global/2014/13

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 54 of 786

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.” 33 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 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 eight regi ons 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

33 NRC, 2011: America’s Climate Choices , The National Academies Press.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 55 of 786 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 U.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 sou thern portion of the region is projected to see 60 additional day s per year above 90 °F by mid-century. Sea levels in the North east 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 56 of 786 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, 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 al ready lost 1,880 square miles of land in the last 80 years due to sea level rise and other contributing factors.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 57 of 786 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 is generally s maller than for other regions of the United States, projected w arming for interior states of the region is larger than coasta l regions by 1 °F to 2 °F. Projections further suggest that ther e 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, Charleston, and Virginia Beach as being specific cities that are at risk due to sea l evel rise, with homes and infrastructure increasingly prone to flooding. Additional impacts of sea level rise are expected f or coastal highways, wetlands, fresh water supplies, and energ y infrastructure. In the Northwest, temperatures increased by about 1 .3 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 58 of 786 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 F to 9.7 o F by the end of the century (depending on future global GHG emissions), with the greatest warming ex pected during the summer. Continued increases in global GHG emiss ions are projected to result in up to a 30 percent decrease in summer precipitation. Earlier snowpack melt and lower summ er stream flows are expected by the end of the century and wi ll affect drinking water supplies, agriculture, ecosystems, a nd hydropower production. Warmer waters are expected to increase disease and mortality in important fish species, including Chin ook and 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 s pread and wildfires to burn larger areas. Other high-elevatio n 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 59 of 786 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 livelih oods of

Native Alaskan communities. By the end of this century, continued increases in GHG emissions are expected to increase temperatures by 10 to 12 °F in the northernmost parts of Alaska, by 8 to 10 °F in the interior, and by 6 to 8 °F across the rest of the s tate. These increases will exacerbate ongoing arctic sea ice lo ss, glacial melt, permafrost thaw and increased wildfire, and t hreaten humans, ecosystems, and infrastructure. Precipitati on is expected to increase to varying degrees across the state. However, warmer air temperatures and a longer growi ng season are***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 60 of 786 expected to result in drier conditions. Native Alas kans are expected to experience declines in economically, nu tritionally, and culturally important wildlife and plant species . Health threats will also increase, including loss of clean water, saltwater intrusion, sewage contamination from thaw ing permafrost, and northward extension of diseases. Wi ldfires will increasingly pose threats to human health as a resu lt of smoke and direct contact. Areas underlain by ice-rich per mafrost across the state are likely to experience ground su bsidence and extensive damage to infrastructure as the permafros t thaws. Important ecosystems will continue to be affected. Surface waters and wetlands that are drying provide breedin g habitat for

millions of waterfowl and shorebirds that winter in the lower 48 states. Warmer ocean temperatures, acidification, a nd declining sea ice will contribute to changes in the location and availability of commercially and culturally importa nt 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, wildfire fre quency and area, and forest insect outbreaks. Sea levels have risen about 7 or 8 inches in this region, contributing to inundat ion of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 61 of 786 Highway 101 and backup of seawater into sewage syst ems 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 coa st 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 als o have impacts on the high-value specialty crops grown in the region as 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 62 of 786 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 r ate 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. 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 63 of 786 High temperatures (more than 100 °F in the Souther n Plains and more than 95 °F in the Northern Plains) are pro jected to occur much more frequently by mid-century. Increase s in extreme heat will increase heat stress for residents, energ y 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 winte rs. Specific vulnerabilities highlighted by the NCA include incr eased demand for water and energy, changes to crop-growth cycles and agricultural practices, and negative impacts on loc al plant and animal species from habitat fragmentation, wildfire s, and changes in the timing of flowering or pest patterns . Communities that are already the most vulnerable to weather and climate extremes will be stressed even further by more freq uent extreme events occurring within an already highly variable climate system. 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 64 of 786 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. 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 island s, future sea surface temperatures are projected to increase 2.3 °F by 2055 and 4.7 °F by 2090 under a scenario that assumes co ntinued***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 65 of 786

increases in emissions. Ocean acidification is also taking place in the region, which adds to ecosystem stress from increasing temperatures. Ocean acidity has increased by about 30 percent since the pre-industrial era and is projected to fu rther increase by 37 percent to 50 percent from present l evels 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 EGUs are by far the largest emitt ers of GHGs among stationary sources in the U.S., primaril y in the form

of CO 2. Among fossil fuel-fired EGUs, coal-fired units are by far the largest emitters. This section describes the am ounts of these emissions and places these amounts in the con text of the U.S. Inventory of Greenhouse Gas Emissions and Sink s 34 (the U.S. GHG Inventory).

34 “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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 66 of 786 The EPA implements a separate program under 40 CFR part 98 called the Greenhouse Gas Reporting Program 35 (GHGRP) that requires emitting facilities that emit over certain threshold amounts of GHGs to report their emissions to the EP A 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 sector. I t provides the information in Table 3 below, which presents to tal U.S. anthropogenic emissions and sinks 36 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 e)) 37,38

35 U.S. EPA Greenhouse Gas Reporting Program Dataset, see http://www.epa.gov/ghgreporting/ghgdata/reportingda tasets.html. 36 Sinks are a physical unitunits or processprocesses that storesstore GHGs, such as forests or underground or deep sea reservoirs of CO 2 . 37 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 38 1 metric ton (tonne) is equivalent to 1,000 kilogr ams (kg) and is equivalent to 1.1023 short tons or 2,204.62 poun ds (lb).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 67 of 786

SECTOR 1990 2005 2013 Energy 39 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) 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. 40 In 2013, fossil fuel combustion by the utility power sector – entities that burn fossil fu el and whose primary business is the generation of electricity – accounted

39 The energy sector includes all greenhouse gases re sulting from stationary and mobile energy activities including f uel combustion and fugitive fuel emissions. 40 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

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 68 of 786 for 38.3 percent of all energy-related CO 2 emissions. 41 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 ) 42

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 GHGRP. Data collected by the GHGRP from large stationary sources in the industrial sector show th at the utility power sector emits far greater CO 2 emissions than any

41 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 42 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

- 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 69 of 786 other industrial sector. Table 5 below presents tot al GHG emissions in 2013 for the largest emitting industri al sectors as reported to the GHGRP. As shown in Table 4 and Tabl e 5, respectively, CO 2 emissions from fossil fuel-fired EGUs are nearly three times as large as the total reported G HG emissions from the next ten largest emitting industrial secto rs in the

GHGRP database combined. Table 5. Direct GHG Emissions Reported to GHGRP by Largest Emitting Industrial Sectors (MMT CO 2 e) 43

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. 44

43 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do. 44 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. Industrial Sector 2013 Fossil Fuel-fired EGUs 2,039.8 Petroleum Refineries Onshore Oil & Gas Production 176.7 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 70 of 786 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 U.S., with smaller amounts being provided by other types of generation, including nuclear and renewables such a s wind, solar, and hydroelectric power. Coal has historical ly provided the largest percentage of fossil-fuel generation. 45 In recent years, the nation has seen a sizeable increase in r enewable generation such as wind and solar, as well as a shi ft from coal to natural gas. 46 In 2013, fossil fuels supplied 67 percent of

45 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. 46 U.S. Energy Information Administration, “Table 7.2 b Electricity Net Generation: Electric Power Sector” data from***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 71 of 786 U.S. electricity, but renewables made up 38 percent of the new generation capacity (over 5 GW out of 13.5 GW). 47 From 2007 to 2014, use of lower- and zero-carbon energy sources has grown, while other major energy sources such as coal and o il have experienced declines. Renewable electricity generat ion, including from large hydro-electric projects, grew from 8 percent to 13 percent over that time period. 48 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. 49 In 2015, the U.S. Energy Information Administration (EIA) projected the need for 28.4 GW of additional base load or intermediate load genera tion capacity through 2020, with approximately 0.7 GW of new coal -fired

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. 47 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. 48 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. 49 Energy Information Administration, Electricity: Form EIA-860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 72 of 786 capacity, 5.5 GW of new nuclear capacity, and 14.2 GW of new NGCC capacity already in development. 50 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 modernization and replacement. 51 For example, the average age of U.S. coal steam units in 2015 is 45 years. 52 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.” 53 While there has been an increased

investment in electric transmission infrastructure since 2005,

50 EIA, Annual Energy Outlook for 2015 with Projections to 2040 , Final Release, available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015). Th e AEO numbers include projects that are under development and mod el-projected nuclear, coal, and NGCC projects. 51 Quadrennial Energy Review, http://energy.gov/epsa/ quadrennialenergy-review-qer 52 We calculated the average age of coal steam units based on the NEEDS inventory, and included units with planned re tirements in 2015-2016. See http://www.epa.gov/airmarkets/documents/ipm/needs_v 514.xlsx. 53 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 73 of 786 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.” 54 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 electricity demand reliably and cost-effectively 55 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. 56 In 2014, natural gas accounted for approximately 27 percent of net generation. 57 The EIA projects that this demand growth will continue, with its Annual Energy Outlook 2015 (AEO

54 American Society for Civil Engineers, 2013 Report Card for America’s Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/. 55 Business Council for Sustainable Energy Comments i n Docket Id. No. EPA-HQ-OAR-2013-0602 at 2 (Nov. 19, 2014). 56 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. 57 Id.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 74 of 786 2015) reference case forecasting that natural gas w ill produce 31 percent of U.S. electric generation in 2040. 58 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 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). 59 QFs were either cogeneration

facilities 60 or small generation resources that use renewables such as wind, solar, biomass, geothermal, or hydroe lectric power

58 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 assumptionsinassumptions in other cases with different macroeconomic growth rates, world oil prices, and r esource 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

. 59 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 60 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 75 of 786 as their primary fuels. 61 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. 62 In its AEO 2015 Reference case, the EIA found that renewable energy will account for 38 per cent of the overall growth in electricity generation from 2013 to 2040. 63 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. 64 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. 65 This trend continued in the

61 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 62 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2014 with Projections to 2040 , at LR-5 (2014). 63 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at E-12(2015). 64 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at 24-25(2015). 65 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 76 of 786 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 least cost plan to be the utility’s most profitable plan.” 66 Energy efficiency has been utilized to meet energy demand to varying levels since that time. As of April 2014, 2 5 states 67 have “enacted long-term (3+ years), binding energy savings targets, or energy efficiency resource standards (E ERS).” 68 Funding for energy efficiency programs has grown ra pidly in

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. 66 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

. 67 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. 68 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 77 of 786 recent years, with budgets for electric efficiency programs totaling $5.9 billion in 2012. 69 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 intensity of power generation, and ensuring a relia ble supply of power at a reasonable cost. 2. Fossil Fuel-fired EGUs Regulated by this 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 powe r 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 co mbustion

69 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 78 of 786 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. 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 drillin g 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 79 of 786 plant (a NGCC unit) is expected to be significantly lower than the cost of generation from a new coal-fired power plant. 70 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 portion of electricity to come from renewable energ y sources such as solar or wind. The federal government has a lso offered incentives to encourage further deployment of other forms of electric generation including renewable energy sour ces and 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. 71 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 2030, a few coal-fired units still

70 Levelized Cost and Levelized Avoided Cost of New G eneration Resources in the Annual Energy Outlook 2015 http://www.eia.gov/forecasts/aeo/electricity_genera tion.html. 71 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 80 of 786 remain as viable projects at various advanced stage s 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, another project, Summit Power's Texas Clean Energy Project (TCEP), which will deploy IGCC with CCS, co ntinues as a viable project. 72 The EIA modeling projects that coal-fired power generation will remain the single largest portion o f the electricity sector beyond 2030. The EIA modeling al so projects that few, if any, new coal-fired EGUs will be built in this

decade and that those that are built will have CCS. 73 Continued progress on these projects is consistent with the E IA modeling that suggests that a small number of coal-fired pow er plants may be constructed. The primary reasons for this rate o f current 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,

72 “Odessa coal-to-gas power plant to break ground th is year”, Houston Chronicle (April 1, 2015). 73 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 coalfired 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 81 of 786 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 whatever fuel is utilized is done so in a way that minimizes CO 2 emissions, as Congress intended with CAA section 11 1. 74 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 development s 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. 75 The current report, AEO 2015 76 : (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

74 These sources received federal assistance under EP Act 2005. See Section III.H.3.g below. However, none of the c onstraints 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. 75 http://www.eia.gov/forecasts/aeo/chapter_legs_regs .cfm. 76 Energy Information Administration’s Annual Energy Outlook for 2015, Final Release available at http://www.eia.gov/forecasts/aeo/index.cfm.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 82 of 786 “planned”); and (ii) projects in the reference case 77 that a very small amount of new (“unplanned”) conventional coal -fired 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 f rom 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 2030. 78 Specifically, the AEO 2015 projects 30.3 GW of addi tional base load or intermediate load generation capacity through 2020 (this includes projects that are under development – i.e., being constructed or in advance planning - and model-proj ected nuclear, coal, and NGCC projects). The vast majorit y of this new electric capacity (20.4 GW) is already under develo pment (under construction or in advanced planning); it includes about 0.7 GW of new coal-fired capacity, 5.5 GW of new nuclear c apacity, and 14.2 GW of new NGCC capacity. The EPA believes that most current fossil fuel-fired projects are already designed to meet limits consistent with this rule (or they have already com menced

77 EIA’s reference case projections are the result of its baseline assumptions for economic growth, fuel supp ly, technology, and other key inputs. 78 Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 2015.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 83 of 786 construction and are thus not subject to these fina l standards). The AEO 2015 also projects an additional 9.9 GW of new base load 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 the new power generation capacity added throug h 2020 is expected to already meet the final emissions standa rds without incurring further control costs. This is also true during the period from 2020 through 2030, where new model-proj ected (unplanned) intermediate and base load capacity is expected to be compliant with the standards without incurring f urther control costs (i.e., an additional 31.3 GW of NGCC and no additional coal, for a total, from 2015 through 203 0, 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 project that coal-fired generation will remain the largest single source of electricity in the U.S. through 2040. Specifically, in the EIA’ s AEO 2015, coal will supply approximately 40 percent of all el ectricity in the electric power sector in both 2020 and 2025.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 84 of 786 The EPA modeling using the Integrated Planning Mode l (IPM), a detailed power sector model that the EPA uses to support power sector regulations, also shows limited future const ruction of new coal-fired power plants under the base case. 79 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. 80 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

79 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation. 80 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 85 of 786 of fuel diversity and include options to diversify new generation capacity beyond natural gas and renewabl e energy. 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 on public comments and on the information con tained in these IRPs, the EPA acknowledges that a small numbe r of new coal-fired power plants may be built in the near fu ture. While this outcome would be contrary to the economic mode ling predictions, the agency understands that economic m odeling may not fully reflect the range of factors that a parti cular company may consider when evaluating new generation options , such as fuel diversification. Further, it is possible that some of this potential new coal-fired construction may occur bec ause developers are able to design projects with specifi c business plans, such as the cogeneration of chemicals, which allow the source to provide competitively priced electricity in specific geographic regions.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 86 of 786 D. Statutory Background The U.S. Supreme Court ruled in Massachusetts v. EPA that

GHGs 81 meet the definition of “air pollutant” in the CAA, 82 and premised its decision in AEP v. Connecticut , 83 that the CAA displaced any federal common law right to compel re ductions in

CO 2 emissions from fossil fuel-fired power plants, on its view that CAA section 111 applies to GHG emissions. 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). 84 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. 85 The EPA listed the two source categories at issue here in the 1970s - listing fos sil fuel-

81 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). 82 549 U.S. 497, 520 (2007). 83 131 S.Ct. 2527, 2537-38 (2011). 84 CAA section 111(b)(1)(A). 85 See generally 40 CFR part 60, subparts D-MMMM.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 87 of 786 fired electric steam generating units in 1971 86 and listing

combustion turbines in 1977. 87 Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new sources” in the category. 88 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. 89 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.” 90 The EPA, through regulations, has determined that certain types of c hanges are exempt from consideration as a modification. 91 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

86 36 FR 5931 (March 31, 1971). 87 42 FR 53657 (October 3, 1977). 88 CAA section 111(b)(1)(B). 89 CAA section 111(a)(2). 90 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. 91 40 CFR 60.2, 60.14(e).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 88 of 786 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. 92 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 that can e ither be normalized to a rate of output or input (e.g., tons of pollution per amount of product produced – a so-called rate-b ased standard), or expressed as a numeric limit on mass of pollutant that may be emitted (e.g., 100 ug/m 3 – parts per billion).

92 40 CFR 60.15.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 89 of 786 Generally, the EPA does not prescribe a particular technological system that must be used to comply with a standard of performance. 93 Rather, sources generally may select any measure

or combination of measures that will achieve the em issions level

of the standard. 94 In establishing standards of performance, the EPA has significant discretion to create subcategor ies based on source type, class, or size. 95 The text and legislative history of CAA section 111 , as well as relevant court decisions, identify the fact ors that the EPA is to consider in making a BSER determination. The system of emission reduction must be technically feasible, th e costs of the system must be reasonable, and the emission sta ndard that the EPA promulgates based on the system of emission reduction must be achievable. In addition, in identifying a B SER, the EPA

must consider the amount of emissions reductions at tributable to the system, and must also consider nonairnon-air quality health and environmental impacts and energy requirements. The case law addressing CAA section 111 makes it clear that the EPA has discretion in weighing costs, amount of emission re ductions, energy requirements, and impacts of non-air quality pollutants, and may weigh them differently for different types of sources or

93 CAA sectionssection 111 (b)(5) and (h). 94 CAA section 111(b)(5). 95 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 90 of 786 air pollutants. We note that under the case law of the D.C. Circuit, another factor is relevant for the BSER de termination: whether the standard would effectively promote furt her deployment or development of advanced technologies. Within the constraints just described, the EPA has discretion in identifying the BSER and the resulting emission sta ndard. 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 which ensure that newly constructed, reconstructed, and modified stationary sources use the best performing technolo gies to limit emissions of harmful air pollutants. In this final action, the EPA is following the same well-established interpre tation and application of the law under CAA section 111 to add ress GHG emissions from newly constructed, reconstructed, an d modified fossil fuel-fired power plants. For each of the sta ndards in this final action, the EPA considered a number of a lternatives and evaluated them against the statutory factors. T he BSER for each category of affected EGUs and the standards of performance

based on these BSER are based 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 91 of 786 section 111(b)(1)(A), 96 and promulgated the first set of standards of performance for sources in that catego ry, which it codified in subpart D. 97 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), 98 and the EPA promulgated standards of performance for that source category i n 1979, which the EPA codified in subpart GG. 99 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

96 36 FR 5931 (March 31, 1971 )). 97 “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. 98 42 FR 53657 (October 3, 1977). 99 “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 92 of 786 that it established for these subcategories. 100 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

. 101 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 did not include specific standards of performance

for CO 2 emissions. 102 Petitioners sought judicial review of the rule, contending, among other issues , that the rule was required to include standards of performance for GHG emissio ns from

EGUs. 103 The January 8, 2014 preamble to the proposed CO 2 standards for new EGUs 104 includes a discussion of the GHGrelated litigation of the 2006 Final Rule as well a s other GHGassociated litigation.

100 44 FR 33580 (June 11, 1979 )). 101 71 FR 38497 (July 6, 2006), as amended at 74 FR 11 861 (March 20, 2009). 102 ”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). 103 State of New York, et al. v. EPA , No. 06–1322

. 104 79 FR 1430, 1444.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 93 of 786 F. Development of Carbon Pollution Standards for Fo ssil Fuelfired 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 units. 77 FR 2239 2 (“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 proposed standard s under CAA

section 111 to limit emissions of CO 2 from newly constructed fossil fuel-fired electric utility steam generating units and newly constructed natural gas-fired stationary comb ustion

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 an associated techn ical support document, Effect of EPAct05 on Best System of Emission Reduct ion

for New Power Plants , the EPA solicited comment on its interpretation of the provisions in the Energy Poli cy Act of 2005 (EPAct05), 105 including how the provisions may affect the

105 See Section III.H.3 (. g ) below. The Energy Policy Act of 2005 (EPAct05) was signed into law by President Geo rge W. Bush on August 8, 2005. EPAct05 was intended to address energy 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 94 of 786 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 349 60; June 2014 proposal). Specifically, the EPA proposed standards 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 95 of 786 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 96 of 786 utility associations and electricity grid operators . Agency officials engaged with labor unions and with leader s representing large and small industries. The agency also met with energy industries, such as coal and natural ga s interests, as well as with representatives of energy-intensive industries, such as the iron and steel, and aluminum industries , to better 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, public health professionals, public health organiza tions, religious organizations, and other community stakeh olders.

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 comments. We received more comments in response to the January 2014 proposal, as discussed in the section below.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 97 of 786 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 (R TC) document summarize and provide the agency’s responses to the comments

received. 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 provide d a 60-day public comment period. On March 6, 2014, in order t o provide the public additional time to submit comments and suppo rting information, the EPA extended the comment period by 60 days, to May 9, 2014, giving stakeholders over 120 days to r eview, and comment upon, the January 2014 proposal, as well as the NODA. A public hearing was held on February 6, 2014, with 1 59 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 utility representatives, trade groups, equipment ma nufacturers, state and local government officials, academia, env ironmental***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 98 of 786 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 such sources, the level of the CO 2 standard based on implementation of partial CCS, the criteri a that define which newly constructed natural gas-fired stationar y combustion turbines will be subject to standards, the establis hment of subcategories based on combustion turbine size, and the rule’s potential effects on the Prevention of Significant Deterioration (PSD) preconstruction permit 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, 201 4. 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 guidelines). A total of 1,322 speakers testified, a nd a further 1,450 attended but did not speak. The speakers were provided the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 99 of 786 opportunity to present data, views, or arguments co ncerning 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). III. Regulatory Authority, Affected EGUs 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 100 of 786 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 new, modified, and reconstructed affected EGUs in new su bpart 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 101 of 786 Administrator promulgates, under section 111(b)(1)( B), “standards of performance for new sources within su ch category.” In this rule, the EPA is establishing standards und er section 111(b)(1)(B) for source categories that it 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, 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 102 of 786 provisions. E.g., CAA sections 202(a)(1), 211(c)(1) , and 231(a)(2)(A ). See ); see also American Electric Power Co. Inc.,

v. Connecticut , 131 S. Ct. 2527, 2539 (2011) (“the(“[T]he Clean

Air Act directs the EPA to establish emissions standards for categories of stationary sources that, ‘in [the Administrator 's] judgment,’ ‘caus[e], or contribut[e] significantly to, air pollution which may reasonably be anticipated to en danger public health or welfare.’ § 7411(b)(1)(A).”) (emphasis ad ded). 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 standards, it is appropria te for the EPA to exercise its authority to adopt a reasonable interpretation of this provision. Chevron U.S.A. Inc. v. NRDC , 467 U.S. 837, 843-44 (1984). 106

106 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 103 of 786 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 (June 24, 2008) (con cluding that the statute provides “the Administrator with signif icant flexibility in determining which pollutants are app ropriate for regulation under section 111(b)(1)(B)” and citing c ases). Further, in directing the Administrator to propose and promulgate regulations under section 111(b)(1)(B), Congress provided that the Administrator should take comment and then

finalize the standards with such modifications “as he deems appropriate.” The D.C. Circuit has considered simil ar 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). 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 Ref ineries, 73***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 104 of 786 Fed. Reg. at 35859-60 (June 24, 2008) (providing re asons why the EPA was not promulgating GHG standards for petroleu m refineries as part of that rule). Though these previous exampl es involved the EPA providing a rational basis for not setting standards for a given pollutant, a similar approach is appropriat e where the

EPA determines that it should set a standard for an additional pollutant for a source category that was previously listed and regulated for other pollutants. 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 GHG air pollution, merit regulation under CAA section 111. As noted, i n 2009, the EPA made a finding that GHG air pollution may reaso nably be anticipated to endanger public health or welfare, a nd in 2010, the EPA denied petitions to reconsider that finding . The EPA extensively reviewed the available science concerni ng GHG pollution and its impacts in taking those actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit upheld t he finding and the denial of petitions to reconsider. 107 In addition, assessments from the NRC, the IPCC, and other organ izations published after 2010 lend further credence to the v alidity of the Endangerment Finding. No information that comme nters have

107 Coalition for Responsible Regulation v. EPA , 684 F. 3d at 102, 119-126 (D.C. Circuit 2012).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 105 of 786 presented or that the EPA has reviewed provides a b asis for reaching a different conclusion. Indeed, current an d evolving

science discussed in detail in Section II.A of this preamble 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 foss il fuelfired 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 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 tha t 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 106 of 786 EGUs. We disagree, for the reasons discussed above. Moreover, as discussed in the January 2014 proposal, 108 even if CAA section 111 required the EPA to make endangerment and cause -orcontribute 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 co ncerned, the

information and conclusions described above should be considered to constitute the requisite endangerment finding. S imilarly, so far as a cause-or-contribute significantly finding is concerned,

the information and conclusions described above sho uld be considered to constitute the requisite finding. The EPA’s rational basis for regulating CO 2 under CAA section 111 is based primarily on the analysis and conclusions in the EP A’s 2009 Endangerment Finding and 2010 denial of petitions t o reconsider that Finding, coupled with the subsequent assessmen ts from the IPCC and NRC that describe scientific developments since those EPA actions. In addition, we have reviewed comments presenting

other scientific information to determine whether t hat information has any meaningful impact on our analys is and

conclusions. More specifically, our approach here – reflected in the

information and conclusions described above – is su bstantially

108 79 FR 1430, 1455-56 (January 8, 2014).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 107 of 786 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) (noting, a mong other things (id. at 119-120), , the “substantial ... body of scientific evidence marshaled by EPA in support of the Endangerment Fin ding ”; ” (id. at 120); the “substantial record evidence that anthropogeni c emissions of greenhouse gases ‘very likely’ caused warming of

the climate over the last several decades ”; ” (id. at 121); “substantial scientific evidence ... that anthropogen ically induced climate change threatens both public health and public

welfare ” . . . [ through “ ] extreme weather events, changes in air quality, increases in food- and water-borne pathoge ns, and increases in temperatures ”; ” (id.); and “substantial evidence ... that the warming resulting from the greenhouse gas emissions could be expected to create risks to water resource s and in general to coastal areas ”). . . . .” (id.)). The facts, unfortunately, have only grown stronger and the pot ential adverse consequences of CO 2 emissions to public health and the

environment more dire in the interim. Accordingly, that***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 108 of 786 approach would support an endangerment finding for this rulemaking. 109

Likewise, if the EPA were required to make a cause- orcontribute-significantly finding for CO 2 emissions from the

109 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 scientific 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. 549 U.SId . at 532-35. In this regard, an endangerment findin g is analogous to setting national ambient air quality s tandards under section 109(b), which similarly call on the A dministrator to set standards that in her “judgment” are “requis ite to protect the public health .””. The EPA is not permitted to consider potential costs of implementation in setti ng these standards. Whitman v. American Trucking Assn’s , 521531 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 t erms such as “necessary and appropriate” thatwhich could suggest (or, in some contexts, 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 consid er costs in determining whether a best system of emiss ion reduction is adequately demonstrated and so can form the basi s for a section 111(b) standard of performance, and the EPA has carefully considered costs here and found them to b e reasonable. See Section V.H and V.I below. See section V. H. an d 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 109 of 786 fossil fuel-fired EGUs as a prerequisite to regulat ing such emissions under CAA section 111, the same facts tha t support our rational basis determination would support such a f inding. As shown in Tables 3 and 4 in this preamble, fossil fu el-fired EGUs are very large emitters of CO 2 . All told, these fossil fuel-fired

EGUs emit almost one-third of all U.S. GHG emission s, and are responsible for almost three times as much as the e missions from the next ten stationary source categories combined. The CO 2 emissions from even a single new coal-fired power p lant may amount to millions of tons each year, and the CO 2 emissions from even a single NGCC unit may amount to one million o r more tons per year. It is not necessary in this rulemaking fo r the EPA to decide whether it must identify a specific threshol d for the amount of emissions from a source category that con stitutes a significant contribution; under any reasonable thre shold or definition, the emissions from combustion turbines and steam generators are a significant contribution. Indeed, these emissions far exceed in magnitude the emissions fro m motor vehicles, which have already been held to contribut e to the endangerment. See Coalition for Responsible Regulation , 684 F. 3d at 121 (“substantial evidence” supports the EPA’s determination “that motor-vehicle emissions of gree nhouse gases***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 110 of 786 contribute to climate change and thus to the endang erment of public health and welfare”). 110 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,

110 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 Section III.G abovebelow 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 111 of 786 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 codifying all the 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 112 of 786 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 subjectin g 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 resu lt, this 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 for the combi nation of the two categories, 111 although as discussed in the previous section, the evidence strongly supports such findings. Thus, the EPA has

111 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 113 of 786 found, in the alternative, that this category of so urces contributes significantly to air pollution which ma y be reasonably anticipated to endanger public health an d welfare.

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, IGCC unit, or combustion turbine (in either simple cycle or combi ned cycle configuration) that meets the applicability criteri a. Affected

EGUs include those that commenced construction afte r January 8,

2014 , and meet the specified applicability criteria and, for modifications and reconstructions, EGUs that commen ced those activities after June 18, 2014 , and meet the specified applicability criteria. To be considered an EGU, the unit must : (1) be capable of combusting more than 250 MMBtu/h (260 GJ/h) heat in put of fossil

fuel ; 112 and (2) serve a generator capable of supplying mor e than 25 MW net to a utility distribution system (i.e., f or sale to the grid). 113 However, we are not finalizing CO 2 standards for

112 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. 113 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 114 of 786 certain EGUs. The EGUs that are not covered by the standards we are finalizing in this rule include: (1) non-fossil fuel units subject to a federally enforceable permit that limi ts the use of fossil fuels to 10 percent or less of their heat in put capacity on an annual basis; (2) combined heat and power (CH P) units that are subject to a federally enforceable permit limit ing annual net-electric sales to no more than the unit’s desig n efficiency multiplied by its potential electric output, or 219 ,000 MWh or less, whichever is greater; (3) stationary combusti on turbines that are not physically capable of combusting natur al gas (e.g., not connected to a natural gas pipeline); (4) utili ty boilers and IGCC units that have always been subject to a f ederally enforceable permit limiting annual net-electric sal es to onethird or less of their potential electric output (e .g., limiting hours of operation to less than 2,920 hours annuall y) or limiting annual electric sales to 219,000 MWh or le ss; (5) 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 this 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 CHP units, as well as certain projects***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 115 of 786 under development. This section discusses these sou rces and our rationale for not issuing standards for them. Becau se the rationale applies to both steam generating units an d combustion turbines, we are describing it here rather than in the separate steam generating unit and combustion turbine discus sions. We discuss the proposed applicability criteria, the to pics where the agency solicited comment, a brief summary of th e relevant comments, and the rationale for the final applicabi lity approach

for these sources.

1. Dedicated Non-fossil Fuel Units The proposed applicability for newly constructed EG Us included those that primarily combust fossil fuels (e.g., coal, oil, and natural gas). The proposed applicability c riteria were

that affected units must burn fossil fuels for more than 10 percent of the unit’s total heat input, on average, over a 3- year period. 114 Under the proposed approach, applicability under

the final NSPS for CO 2 emissions could have changed on an annual basis depending on the composition of fuel burned. We solicited comment on several aspects of the proposed applicab ility criteria for non-fossil fuel units. Specifically, w e solicited comment on a broad applicability approach that woul d include non-fossil fuel-fired units as affected units, but that would

114 We refer to the fraction of heat input derived fro m fossil fuels as the "fossil fuel-use criterion."***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 116 of 786 impose an alternate standard when the unit fires fo ssil fuels for 10 percent or less of the heat input during the 3-year applicability-determination period. We solicited co mment on whether, if such a subcategory is warranted, the ap plicabilitydetermination period for the subcategory should be 1-year or a 3-year rolling period. We also solicited comment on whether the standard for such a subcategory should be an altern ate numerical

limit or "no emission standard." While the proposed exemption applied to all non-fos sil fuels, commenters focused on biomass-specific issues. Some commenters stated that the proposed standards were not developed

to include dedicated biomass-fired units and that n one of the analyses supporting the standards included biomass- fired units. These commenters also stated that the proposed stan dards have not been adequately demonstrated as achievable by t hese units and that the rule offered no basis for regulating s ources that combust insignificant amounts of fossil fuels. They suggested

that if dedicated biomass units must be included un der these CAA section 111 standards for fossil fuel-fired units, they should be included in a separate subcategory after a subse quent proposal and comment period based on relevant data. most commenters focused on biomass-specific issues. Many commenters supported an exclusion for biomass-fired units that fire no more than 10 percent fossil fuels. Some commenters sugge sted that the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 117 of 786

exclusion for biomass-fired units should be raised to a 25 percent fossil fuel-use threshold. Conversely, some commenters supported standards for dedicated biomass units because they are typically operated with higher heat rates than coal units and model results conducted by the EPA using IPM show that biomass generation is e xpected to quadruple over the next 10 years. These commenters said that dedicated biomass units should be regulated consist ently with coal units. One commenter supported ensuring that t he CO 2 standards issued pursuant to CAA section 111(d) con tinue to apply to existing EGUs when those EGUs modify or re construct in ways that cause the units to derive 10 percent or l ess of their heat input from fossil fuels because allowing modif ied and reconstructed EGUs to escape 111(d) standards would undermine the coherence of the proposed 111(d) regulatory sys tem. Many commenters supported the proposed 3-year avera ging period for the fossil fuel-use criterion because it provides greater flexibility for operators to use fossil fue ls when supply chains for biogenicthe primary non-fossil fuels are disrupted, during unexpected malfunctions of biomassthe primary

non-fossil fuel handling systems, or when the unit’s maximum 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 118 of 786 requirements under the EPA’s Mercury and Air Toxics Standards (MATS) and would allow biomass-non-fossil fuel- fired units to

use some fossil fuels for flame stabilization witho ut triggering applicability. Some commenters recommended including an additional 15 percent fossil fuel-use threshold tha t would be

calculated on an annual basis. Some commenters requested that the EPA clarify the method an operator should use d uring the first 3 years of operations to determine if a parti cular unit will meet the 10 percent fossil fuel-use threshold. Others asked whether or not an affected facility has a complianc e obligation during the first 3-year period and, if an affected facility does not meet the 10 percent fossil fuel-use threshold d uring several 12-month periods during the first 3 years, whether compliance 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 operating near the threshold could move in and out of the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 119 of 786 regulatory system, which would provide complication s for compliance, enforcement, and permitting. After considering these comments, the EPA has concl uded that the proposed fossil fuel-use criterion based o n the actual amount of fossil fuel burned is not an ideal approa ch to determine applicability. As commenters pointed out, facilities, permitting authorities, and the public would not kn ow when construction is commenced whether a facility will b e subject to the final NSPS, and after operation has commenced, a unit could move in and out of applicability each year. The int ent of this rulemaking is to establish CO 2 standards for fossil fuel-fired EGUs, not for non-fossil fuel-fired EGUs. Therefore , to simplify compliance and establish CO 2 standards for only those sources which we set out to regulate, we are finalizing a f ossil fueluse criterion that will exempt dedicated non-fossil units. Specifically, units that are capable of burning 50 percent or more non-fossil fuel are exempt from the final stan dards so long as they are subject to a federally enforceable perm it that limits their use of fossil fuels to 10 percent or l ess of their heat input capacity on an annual basis. This approa ch establishes clear applicability criteria and avoids the prospect of units moving in and out of applicability based o n their actual fuel use in a given year. Consistent with th e applicability approach in the steam generating unit criteria***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 120 of 786 pollutant NSPS, subpart Da, the final fossil fuel-u se criterion does not include “constructed for the purpose of” l anguage. Therefore, an owner or operator could change a unit ’s applicability in the future by seeking a modificati on of the unit’s permit conditions. A unit with the appropria te permit limitation will not be subject to the requirements in this rulemaking. Similarly, an existing unit that takes a permit limitation restricting fossil-fuel use would no lon ger be an affected unit for the purposes of 111(d) state plan s. This is

consistent with our intent to reduce GHG emissions from fossil

fuel-fired EGUs. We considered using either an annual or 3-year aver age for calculating compliance with the final fossil fuel-u se criterion. Ultimately, we concluded that an annual average wou ld provide sufficient flexibility for dedicated non-fossil uni ts to combust

fossil fuels for flame stabilization and other anci llary purposes, while maintaining consistency with the 12 -month compliance periods used for most permit limitations . A 3-year average potentially would allow units to combust a significant quantity of fuels in a given year, leading to highe r CO 2 emissions, so long as they curtailed fossil-fuel us e in a later year. This would defeat the purpose of the criterio n, which is to exempt dedicated non-fossil units only. Finally, we are finalizing the 10 percent fossil-fuel use threshold in relation***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 121 of 786 to a unit’s heat input capacity rather than its act ual heat input, which is consistent with past approaches we have taken under the industrial boiler criteria pollutant NSPS

. 2. Industrial CHP Units Another approach to generating electricity is the u se of CHP units. A CHP unit can use a boiler, combustion turbine, reciprocating engine, or various other generating t echnologies to generate electricity and useful thermal energy i n a single, integrated system. CHP units are generally more eff icient than conventional power plants because the heat that is normally wasted in a conventional power generation cooling s ystem (e.g., cooling towers) is instead recovered as useful ther mal output. While the EPA did propose some applicability provis ions specific to CHP units (e.g., subtract purchased power of adj acent facilities when determining total electric sales), in general, the proposed applicability criteria for electric-on ly units and CHP units were similar. The intent of the proposed total and percentage electric sales criteria was to cover onl y utility CHP units, not industrial CHP units. To the extent that the proposal’s applicability provisions would have the effect of covering industrial CHP units, we solicited comment on an appropriate applicability exemption, and the criter ia for that exemption, for highly efficient CHP facilities.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 122 of 786 Many commenters supported the exclusion of CHP unit s as a means of encouraging capital investments in highly efficient and reliable distributed generation technologies. These commenters recommended that the EPA adopt an explicit exemptio n for CHP

units at facilities that are classified as industri al (e.g., gas-fired CHPs within SIC codes 2911 – petroleum re fining, 13 – oil and gas extraction, and other industrial SIC co des as appropriate). They also stated that the EPA should exclude CHP units that have an energy savings of 10 percent or more compared to separate heat and power. One commenter suggested that the final rule should cover only industrial-commercial- institutional CHP units that supply, on a net basis, more than tw o-thirds of their potential combined thermal and electric energ y output and more than 450,000 MWh net-electric output to a util ity power distribution system on an annual basis for five con secutive calendar years. The commenter also suggested that C HP units which have total thermal energy production that app roaches or exceeds their total electricity production should b e exempted. Other commenters suggested exempting CHP units by f uel type or based on the definition of potential electric ou tput. For example, some commenters suggested modifying the pe rcentage electric sales threshold to be based on net system efficiency (including useful thermal output) rather than the r ated netelectric-output efficiency. They also suggested tha t the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 123 of 786 applicability criteria should use a default efficie ncy of 50 percent for CHP units. Some commenters suggested th at a CHP unit should not be considered an affected EGU if 20 perc ent or more of its total gross or net energy output consisted o f useful thermal output on a 3-year rolling average basis. O ther commenters said that highly efficient CHP units tha t achieve an overall efficiency level of 60 to 70 percent or hig her should be excluded from applicability. The intent of this rulemaking is to cover only util ity CHP units, because they serve essentially the same purp ose as electric-only EGUs (i.e., the sale of electricity t o the grid). Industrial CHP units, on the other hand, serve a di fferent primary purpose (i.e., providing useful thermal out put with electric sales as a by-product). With these facts i n mind and after considering the comments, the EPA has conclud ed that it is appropriate to consider two factors for the final C HP exemption: (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 of the factors we identified. Specifically, the EPA has co ncluded that

SIC code classification is not a sufficient indicat or of the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 124 of 786 purpose (i.e., it does not correlate to useful ther mal output) or environmental benefits (i.e., efficiency) of a u nit. Further, an exemption based on SIC code could result in circ umvention of the intended applicability. For example, this appro ach would allow a new EGU to locate near an industrial site, provide a trivial amount of useful thermal output to that sit e, sell electricity to the grid, and nonetheless avoid appl icability. Similarly, increasing the electric sales criteria t o two-thirds of potential electric output and 450,000 MWh would essentially amount to a blanket exemption that tells us nothing about the primary purpose or efficiency of the unit. On the other hand, exemptions based on useful therm al output being greater than 20 percent of total outpu t, thermal output being greater than electric output, or overa ll design efficiency value would identify whether the primary purpose of a unit is to generate thermal output, but they would not recognize the environmental benefits of highly efficient CHP units. While overall efficiency may appear to be a good indicato r of environmental benefits, this is not always the case with CHP units. Overall efficiency is a function of both eff icient design and the power to heat ratio (the amount of electric ity relative to the amount of useful thermal output). For exampl e, boilerbased CHP units tend to produce large amounts of us eful thermal output relative to electric output and tend to have high overall***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 125 of 786 efficiencies. For units producing primarily useful thermal output, the equivalent separate heat and power effi ciency (i.e., the theoretical overall efficiency if the electrici ty and useful thermal output were produced by a stand-alone EGU a nd standalone boiler) would approach that of a stand-alone boiler (e.g., 80 percent). However, combustion turbine-based CHP units tend to produce relatively equal amounts of electricity and useful thermal output. In this case, the equivalent separa te heat and power efficiency would be closer to 65 percent. The refore, an exemption based on overall efficiency is not an ind ication of the fuel savings a CHP unit will achieve relative t o separate heat and power. Further, this approach would encour age the development of CHP units that just meet the efficie ncy exemption criterion and would still cover many combustion tur bine-based industrial CHP units. Conversely, while an exemptio n based on fuel savings relative to separate heat and power wo uld recognize the environmental benefit of highly efficient CHP u nits, it would not consider the primary purpose of the CHP u nit. In the end, the EPA has concluded that maintaining the proposed percentage electric sales criterion with t wo adjustments addresses both factors with which we ar e concerned. First, we are changing the definition of “potential electric output” to be based on overall net efficiency at th e maximum electric production rate, instead of just electric- only***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 126 of 786 efficiency. Second, we are changing the percentage electric sales criterion to reflect the sliding scale, which is the overall design efficiency, calculated at the maximu m useful thermal rating of the CHP unit (e.g., a CHP unit wi th a extraction condensing steam turbine would determine the efficiency at the maximum extraction/bypass rate), of the unit multiplied by the unit’s potential electric output instead of one-third of potential electric output as proposed. This approach recognizes the primary purpose of industri al CHP units by providing a more generous percentage electric sa les exemption to CHP units with high thermal output. As described previously, CHP units with high thermal loads tend to be more e fficient and will therefore have a higher allowable percentage e lectric sales. By amending both the definition of “potentia l electric output” and the electric sales threshold, we assure 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 the environmental benefits of increased efficiency by encouraging industrial CHP units to be designed as efficiently***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 127 of 786 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 tha t limits annual total electric sales to less than or equal t o the unit’s design efficiency multiplied by its potential elect ric output or 219,000 MWh, 115 whichever is greater. This final applicability criterion will only cover CHP units that condense a significant portion of steam generated by the unit and use the electric power generated as a result of condensing that stea m to supply electric power to the grid. CHP facilities that do not have a condensing steam turbine (e.g., combustion turbine- based CHP units without a steam turbine and boiler-based syst ems with a backpressure steam turbine) would generally not be physically capable of selling enough electricity to meet the a pplicability criterion, even if they sold 100 percent of the ele ctricity generated and did not subtract out the electricity used by the thermal host(s). The EPA has concluded that this is appropriate because these sources are industrial by design and provide mostly useful thermal output.

115 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 128 of 786 CHP facilities with a steam extraction condensing s team turbine will determine their potential electric out put based on their efficiency on a net basis at the maximum elec tric production rate at the base load heat input rating (e.g., the CHP is condensing as much steam as possible to crea te electricity instead of using it for useful thermal output). We have concluded that it is necessary for CHP units w ith extraction condensing steam turbines to calculate t heir potential electric output at the maximum condensing level to avoid circumvention of the applicability criteria. For example, to avoid applicability a CHP unit could locate next to an industrial host and have the capability of selling significant quantities of useful thermal output without ever ac tually intending to supply much, if any, useful thermal ou tput to the industrial host. If we calculated the potential ele ctric output at the maximum level of thermal output, this type o f CHP unit could operate at full condensing mode at base load conditions for the entire year and still not exceed the electr ic sales threshold. During the permitting process, the owner or operator will be able to determine if the unit is subject to the final

standards in this rule. New EGUs with only limited useful thermal output wi ll be subject to the final standards, but the vast majori ty of new CHP

units will be classified as industrial CHP and will not be***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 129 of 786 subject to the final standards. The EPA has conclud ed that this approach is similar to exempting CHP facilities tha t sell less than half of their total output (electricity plus t hermal), but has the benefit of accounting for overall design ef ficiency. This approach both limits applicability to the indu strial CHP units and encourages the installation of the most e fficient CHP systems because more efficient designs will be able to have higher permitted electric sales while not being sub ject to the

CO 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 included in this source category. The refore, even if one of these types of units meets the general he at input and electric sales criteria, we are not finalizing CO 2 emission standards for municipal waste combustors subject to subpart Eb of this part and commercial and industrial solid wa ste 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 130 of 786 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 today’s action.this final rule. We again note that these sources, if and when constructed, could be ultimately subject to the 1,400 lb CO 2 /MWh-g standard, especially if there is no engineering basis, or demonstrated action in reliance, showing that the new source could not meet that sta ndard.

E. Coal Refuse In the April 2012 proposal, we solicited comment on subcategorizing and exempting EGUs that burn over 7 5 percent coal refuse on an annual basis. Multiple commenters supported the exemption, citing numerous environmental benefi ts of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 131 of 786 remediating coal refuse piles. Observing that coal refuse-fired EGUs typically use fluidized bed technologies, othe r commenters disagreed with any exemption, specifically citing t he N 2 O emissions from fluidized bed boilers. In light of t he 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, we sought additional comme nts regarding a subcategory for coal refuse-fired EGUs in the Jan uary 2014 proposal. Specifically, we requested additional inf ormation on

the net environmental benefits of coal refuse-fired EGUs and information to support an appropriate emissions sta ndard for coal refuse-fired EGUs. One commenter on the April 2012 proposal stated that existing coal refuse piles are naturall y combusting at a rate of 0.3 percent annually, and we requested comment on this rate and the proper approach to account for na turally occurring emissions from coal refuse piles in the J anuary 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 suggested that the EPA establish BSER for

GHGs at modified coal refuse CFBs as a boiler tune- up that must be performed at least every 24 months. Commenters s tated that***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 132 of 786 the EPA should exempt coal refuse CFB units relativ e to their CO 2 emissions to the extent that these units offset the uncontrolled ground level emissions from spontaneous combustion of legacy coal refuse stockpiles and noted that the mining of coal waste not only produces less emissions in the long term, but also helps to reclaim land that is currently used to sto re coal waste. In contrast, one commenter saw no legitimate basis for coal refuse to be subcategorized and stated that theyit should

be treated in the same manner as all other coal-fir ed EGUs. The EPA has concluded that an explicit exemption or subcategory specifically for coal refuse-fired EGUs is not appropriate. The costs faced by coal refuse facilit ies to install CCS are similar to coal-fired EGUs burning any of the primary coals, and the final applicable requirement s and standards in the rule do not preclude the developme nt of new coal refuse-fired units without CCS. Specifically, we are not finalizing CO 2 standards for industrial CHP units. Many existing coal refuse-fired units are relatively small and de signed as CHP units. Due to the expense of transporting coal refu se long distances, we anticipate that any new coal refuse-f ired 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 133 of 786 F. Format of the Output-based Standard 1. Net and Gross Output-based Standards 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. 116 For a non-CHP EGU, gross output is the electricity generation measured at the generator terminals. However, we so licited 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 gro ss 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 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 t o recognize

116 79 FR 1447-48.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 134 of 786

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 efficiency motors, pumps, and fans. For modified and reconstru cted 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 NGCC designs, the differ ence between a gross-output standard and a net-output standard h as a limited impact on environmental performance. Auxiliary load s are more significant for modified and reconstructed boilers and IGCC units, and the EPA proposed standards on a net outp ut basis for

these units. The rationale included that this would enable owners/operators of these types of units to pursue projects that reduce auxiliary loads for compliance purposes. How ever, the EPA solicited comment on finalizing the standards on a gross-output basis. We also proposed to use either gross-output or net-output bases for each respective subcategory of EGUs (i.e. , utility boilers, IGCC units, and combustion turbines) consi stently across all CAA section 111(b) standards for new, mo dified, and

reconstructed EGUs. Many commenters supported gross-output-based standa rds, maintaining that a net-output standard penalizes th e operation of air pollution control equipment. Several comment ers disagreed***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 135 of 786 with the agency's proposed rationale that a net-out put standard would provide incentive to minimize auxiliary loads . The commenters believe utility commissions and existing economic forces already provide utilities with appropriate i ncentives to properly manage all of these factors. Some commente rs supported a gross-output-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 includes a net-outputbased 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 136 of 786 technology that should be required, particularly fo r newly

constructed units. Other commenters, however, maintained that the fina l rule should strictly require compliance on a net output- basis. They believe that this is the only way for the standards to minimize the carbon footprint of the electricity delivered t o consumers. These commenters believe that, at a minimum, net-ou tput-based standards should be included as an option in the fi nal rule. We are only finalizing gross-output-based standards for utility boilers and IGCC units. Providing an altern ate netoutput-based standard that is based on gross-output -based emissions data and an assumed auxiliary load is mos t appropriate when the auxiliary load can be reasonably estimated and the choice between the net- and gross-output-based stan dard will not impact the identified BSER. For example, the auxili ary load for combustion turbines is relatively fixed and small, approximately 2.5 percent, so the choice between a gross and net- output-based standard will not substantially impact technology c hoices. However, in the case of utility boilers, we have co ncluded that

we do not have sufficient information to establish an appropriate net-output-based standard that would no t impact the identified BSER for these types of units. The BSER for newly constructed steam generating units is based on the use of partial CCS. However, unlike the case for combustio n turbines,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 137 of 786 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 e quipment for feedwater heating or steam augmentation) or a coal- fired EGU cofiring natural gas would have lower non-CCS related auxiliary loads and, because the amount of CCS needed to comp ly with the standard would also be smaller, the CCS auxiliary l oads would also be reduced. Therefore, we cannot identify an a ppropriate assumed auxiliary load to establish an equivalent n et-outputbased standard. In addition, many IGCC facilities ( which could be used as an alternative technology for complying with the standard of performance; see Sections IV.B and V.P below) have been proposed or are envisioned as co-production fa cilities (i.e., to produce useful by-products and chemicals along with electricity). As noted in the proposal, we have con cluded that predicting the net electricity at these co-producti on facilities would be more challenging to implement under these

circumstances. In contrast, based on further evaluation and review of issues raised by commenters, the EPA is finalizing the CO 2 standard for combustion turbine EGUs in a format th at is similar to the current NSPS format for criteria pollutants. The default***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 138 of 786 final standards establish a gross-output-based stan dard. 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. 117 However, many permitting authorities commented persuasively that the environ mental benefits of using net-output-based standards can ou tweigh any additional complexities for particular units, and h ave indeed adopted net-output standards in recent GHG operatin g permits for combustion turbines. We expect this trend to contin ue and have concluded that it is appropriate to support the exp anded use of net-output-based standards, and therefore are allow ing certain sources to elect between gross output-based and net -output-based 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. 118

117 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. 118 Assuming a 3 percent auxiliary load for the NGCC s ystem.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 139 of 786 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 have prescribed various “discount factors” of the measured useful thermal output to be used when dete rmining the emission rate. We proposed that 75 percent credit i s the appropriate discount factor for useful thermal outp ut, and we solicited comment on a range from two-thirds to thr ee-fourths credit for useful thermal output in the proposal fo r newly constructed units and two-thirds to one hundred per cent credit in the proposal for modified and reconstructed unit s. The 75 percent credit was based on matching the emission r ate, but not the overall emissions, of a hypothetical CHP unit t o the proposed emission rate.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 140 of 786 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 state approache s for determining emission rates for CHP units.

Based on further consideration and review of the co mments submitted, we are finalizing 100 percent credit for useful thermal output for all newly constructed, modified, and

reconstructed CHP sources. We 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 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 approp riately recognizes the environmental benefit of CHP.

G. CO 2 Emissions Only The air pollutant regulated in this final action is greenhouse gases. However, the standards in this ru le are expressed in the form of limits on only emissions o f CO 2 , and not***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 141 of 786 the other constituent gases of the air pollutant GH Gs. 119 We are not establishing a limit on aggregate GHGs or separ ate emission limits for other GHGs (such as methane (CH 4 ) or nitrous oxide (N 2 O)) as other GHGs represent less than 1 percent of total estimated GHG emissions (as CO 2 e) from fossil fuel-fired electric power generating units. 120 Notwithstanding this form of the standard, consistent with other EPA regulations add ressing GHGs, the air pollutant regulated in this rule is GHGs. 121 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. We note d that the

119 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. 120 EPA Greenhouse Gas Reporting Program; www.epa.gov/ghgreporting //. 121 See 77 FR 31257-30 (June 3, 2010).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 142 of 786

D.C. Circuit has handed down numerous decisions tha t interpret this CAA provision, including its component element s, and we

reviewed that case law in detail. 122 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. 123 2. CAA Requirements 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 section 111(b)(1)(A). Following that listing, the EPA “shall publish proposed regulations, establishi ng federal

122 79 FR 1430, 1462 (January 8, 2014). 123 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 with this rule. Our interpretations a nd applications of these requirements in the two rulem akings are generally consistent with each other except to the extent that they reflect distinctions between new and existing sources. For example, the BSER for new industrial facilities, wh ich are expected to have lengthy useful lives, should inclu de, at a minimum, the most advanced pollution controls avail able, but for existing sources, the additional costs of retrofit may render those controls too expensive.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 143 of 786 standards of performance for new sources within suc h category” and then “promulgate

.... . . such standards” within a year after proposal. CAA section 111(b)(1)(B). The EPA “may di stinguish among classes, types, and sizes within categories o f new sources for the purpose of establishing such standards.” CA A section 111(b)(2). The term “standard of performance” is de fined to “mean[] a standard for emissions of air pollutants which reflects the degree of emission limitation achievab le through the application of the best system of emission redu ction 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.” CAA 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 histor y provides***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 144 of 786 guidance in interpreting this provision. 124 In addition, the D.C. Circuit has reviewed rulemakings under CAA section 111 on numerous occasions during the past 40 years, handin g down

124 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 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. Even so, because parts of the definitio n as it read under the 1977 CAAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative history, a nd the interpretation in the case law, of those parts of t he definition in the case law remain relevant to the definition a s it reads today.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 145 of 786 decisions dated from 1973 to 2011, 125 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 emiss ion limits that the EPA promulgates must be “achievable” by ap plication of a “system of emission reduction” that the EPA deter mines to be the “best” that is “adequately demonstrated,” “taki ng into account ... cost ... nonair quality health and environm ental impact and energy requirements.” The D.C. Circuit has sta ted that, in determining the “best” system, the EPA must also ta ke into account “the amount of air pollution” 126 reduced and the role of “technological innovation.” 127 The Court has emphasized that the EPA has discretion in weighing those various factor s. 128,129

125 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). 126 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981). 127 See Sierra Club v. Costle, 657 F.2d at 347. 128 See Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999). 129 Although the section 111(a)(1) may be read to state that 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 146 of 786 Our overall approach to determining the BSER, which incorporates the various elements, is as follows: F irst, the EPA identifies the “system[s] of emission reduction” th at have been “adequately demonstrated” for a particular source c ategory. Second, the EPA determines the “best” of these syst ems after evaluating extent of emission reductions, costs, an y nonairnonair health and environmental impacts, and energy requi rements. And third, the EPA selects an achievable standard f or emissions - here, the emission rate - based on the performanc e of the

BSER. The remainder of this subsection discusses th e various elements in that analytical approach. a. “System[s] of emission reduction ... adequately demonstrated” 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.

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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 147 of 786 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.” 130 It does not mean that the system “must be in actual ro utine use

somewhere.” 131 Rather, the Court has said, “[t]he Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonab leness and cannot be based on ‘crystal ball’ inquiry.” 132 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.” 133 Ultimately, the analysis “is partially dependent on ‘lead time,’” that is, “ the time in which the technology will have to be available.” 134 Per CAA section 111(e), standards of performance under CAA section

130 Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), cert. denied , 416 U.S. 969 (1974). 131 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). 132 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 133 Sierra Club v. Costle , 657 F.2d 298, 364 (1981). 134 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 148 of 786 111(b) are applicable immediately after the effecti ve date of their promulgation

(1) Technical feasibility of the best system of emissio n 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).

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, 135 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

135 79 FR at 1464 (January 8, 2014).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 149 of 786 “exorbitant,” 136 “greater than the industry could bear and survive,” 137 “excessive,” 138 or “unreasonable.” 139 For convenience, in this rulemaking, we use ‘reasonableness’ to desc ribe costs well within the bounds established by this jurispru dence. 140

136 Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999). 137 Portland Cement Ass’n v. EPA , 513 F.2d 506, 508 (D.C. Cir. 1975). 138 Sierra Club v. Costle , 657 F.2d 298, 343 (D.C. Cir. 1981). 139 Sierra Club v. Costle , 657 F.2d 298, 343 (D.C. Cir. 1981). 140 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 as serted 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 150 of 786

The D.C. Circuit has indicated that the EPA has sub stantial

discretion in its consideration of cost under secti on 111(a). In several cases, the Court upheld standards that enta iled significant costs, consistent with Congress’s view that “the costs of applying best practicable control technolo gy be considered by the owner of a large new source of po llution as a normal and proper expense of doing business.” 141 See Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, 440 (D.C. Cir. 1973); 142 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”). 143 Moreover, section 111(a) does not provide specific direction regardin g what metric or metrics to use in considering costs, again affor ding the EPA

to be a convenient term for referring to the cost s tandard as established in the case law. 141 1977 House Committee Report at 184. 142 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). 143 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 151 of 786 considerable discretion in choosing a means of cost

consideration. 144 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 a re considered on a source-specific basis, an industry/national ba sis, or both, they are reasonable. See Sections V.H and I below. (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. As the D.C. Circui t has explained, this requirement makes explicit that a s ystem cannot be “best” if it does more harm than good due to cro ss-media environmental impacts. 145 The EPA has carefully considered such cross-media impacts here, in particular potential i mpacts to underground sources of drinking water posed by CO 2 sequestration, and water use necessary to operate carbon capture s ystems. See

Sections V.N and O below.

144 See, e ,. g., Husqvarna AB v. EPA , 254 F. 3d 195, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a specific method of cost analysis, the EPA may make a reasoned choice as to how to analyze costs).

145 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 152 of 786 (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” e ntail, for example, the impact, if any, of the system of emiss ion reduction on the source’s own energy needs. In this rulemakin g, as discussed below in Section V.O.3, the EPA considere d the parasitic load requirements of partial CCS. The EPA is finding here that whether energy requirements are considere d 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 153 of 786 the optimal standard for controlling ... emissions”). 146 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,” the EPA must consider the amount of emission reductions that the system would yield. 147 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 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

146 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.” 147 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 154 of 786 time, and not only on a plant-specific level at the time of the rulemaking. 148 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. 149 The Court has upheld 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 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. 150

148 79 FR 1430, 1465 January 8, 2014) (citing Sierra Club v. Costle , 657 F.2d at 351). 149 Sierra Club v. Costle , 657 F.2d at 331 (citations omitted) (citing legislative history). 150 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 155 of 786

Some commenters objected that this case law did not allow

the EPA to ignore source-specific impacts (particularly cost impacts) by basing determinations solely on impacts at a regional or national level. In fact, the EPA’s cons ideration of cost, non-air quality impacts, and energy requireme nts reflect source-specific impacts, as well as (for some consi derations) impacts that are sector-wide, regional, or national . See Section

V.H.6 below. c. Achievability of the standardStandard for emissionsEmissions 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’] 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 proj ected to be available to new sources at the time they are const ructed that

will allow them to meet the standard. 151 Moreover, according to

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). 151 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 156 of 786 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.” 152 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.’” 153 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 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.” 154

EPA’s analysis recognizes that the standard for emi ssions must be achievable through the application of the BSER. 152 Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 433-34 (D.C. Cir. 1973), cert. denied , 416 U.S. 969 (1974). 153 Nat’l Lime Ass’n v. EPA , 627 F.2d 416, 433, n.46 (D.C. Cir. 1980). 154 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 157 of 786 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 useUse and developmentDevelopment of technologyTechnology 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 innov ation as one of the factors in determining the “best system of e mission

reduction.” 155 The Court grounded its reading in the statutory tex t. 156 In addition, in the January 2014 proposal, we noted th at the Court’s interpretation finds additional support in the

155 See 79 FR 1430, 1465 (January 8, 2014), Sierra Club v. Costle , 657 F.2d at 346-47. 156 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.”).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 158 of 786 legislative history. 157 We also explained that the legislative history identifies three different ways that Congre ss designed CAA section 111 to authorize standards of performan ce that promote technological improvement: (i) the developm ent of technology that may be treated as the “best system of emission reduction . . . adequately demonstrated” under sect ion 111(a)(1); (ii) the expanded use of the best demons trated technology; and (iii) the development of emerging t echnology. 158 Even if the EPA were not required to consider techn ological innovation as part of its determination of the BSER , it would be reasonable for the EPA to consider it, either becau se technological innovation may be considered an eleme nt of the term “best,” or because the term “best system of em ission reduction” is ambiguous as to whether technological innovation may be considered. The interpretation is likewise c onsistent with the evident purpose of section 111(b) to requi re new sources to maximize emission reductions using state -of-the-art

means of control.

157 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”). 158 79 FR at 1465 (citing case law and legislative history).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 159 of 786 Commenters stated 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. e. Agency discretionDiscretion 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 balance multiple concerns when promulgating a NSPS, ” 159 and emphasized that “[t]he text gives the EPA broad dis cretion to weigh different factors in setting the standard.” 160 In Lignite Energy Council v. EPA , 198 F.3d 930 (D.C. Cir. 1999), the Court

159 Sierra Club v. Costle , 657 F.2d at 319. 160 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 160 of 786

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. 161

f. Lack of requirementRequirement that standard be able to be

metStandard Must Be Met by all sourcesAll Sources In the January 2014 proposal, the EPA proposed that , under CAA section 111, an emissions standard may meet the requirements of a “standard of performance” even if it cannot be met by every new source in the source category that would have c onstructed in

the absence of that standard. As described in the J anuary 2014 proposal, the EPA based this view on (i) the legisl ative history of CAA section 111, read in conjunction with the le gislative history of the CAA as a whole; (ii) case law under analogous CAA provisions; and (iii) long-standing precedent in th e EPA rulemakings under CAA section 111. 162

161 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.”).

162 79 FR 1430, 1466 (January 8, 2014).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 161 of 786 Commenters contested this assertion, arguing that a 111(b) standard must be achievable by all new sources. We continue to take the same position as at proposal for the reaso ns described there. We note that as a practical matter, in this rulemaking, the issue of whether all new steam-generating sourc es can implement partial-capture CCS is largely dependent on the geographic scope of geologic sequestration sites. A s discussed below in Section V.M, geologic sequestration sites are widely available, and a steam-generating plant with partia l CCS that is sited near an area that is suitable for geologic se questration can serve demand in a large area that may not have sequestration sites available. In any event, the standard of 1,40 0 lb CO 2 /MW-g that we promulgate in this final rule can be achiev ed by new steam generating EGUs – including new utility boile rs and IGCC units - through co-firing with natural gas in lieu of installing partial CCS, which moots the issue of the geographi c availability of geologic sequestration. g. EPAct05 The Energy Policy Act of 2005 (“EPAct05”) authorize s assistance in the form of grants, loan guarantees, as well as

Federalfederal tax credits for investment in “clean coal technology.” Sections 402(i), 421(a), and 1307(b) ( adding section 48A(g) to the Internal Revenue Code (“IRC”) ) address the extent to which information from clean coal project s receiving***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 162 of 786 assistance under the EPAct05 may be considered by t he EPA in determining what is the best system of emission red uction adequately demonstrated. Section 402(i) of the EPAc t05 limits

the use of information from facilities that receive assistance under EPAct05 in CAA section 111 rulemakings:

“ No technology, or level of emission reduction, sole ly 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

........” 163 IRC section 48A(g) contains a similar constraint co ncerning the use of technology or level of emission reductio n from EGU

facilities for which a tax credit is allowed:

“ No use of technology (or level of emission reductio n 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

.... ....”

163 Codified at 42 U.S.C. 15962(a). EPAct05 section 42 1(a) similarly states: “No technology, or level of emiss ion reduction, shall be treated as adequately demonstra ted for purpose [sic] of section 7411 of this title, ... sole ly by reason of the use of such technology, or the achievement o f such emission reduction, by one or more facilities recei ving assistance under section 13572(a)(1) of this title”

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 163 of 786 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 sections 402(i) and 421(a), the EPA proposed that t hese provisions barred consideration where EPAct05-assis ted facilities were the sole support for the BSER deter mination, but that these sources could support a BSER determinati on so long as there is additional evidence supporting the determi nation. 164 In addition, the EPA viewed the two prohibitions as re lating only to the technology or emissions reduction for which assistance was given. 165 The EPA likewise interpreted IRC section 48A(g) – based on the plain language and the context provide d by sections 402(i) and 421(a) – to mean that use of technology, or emission performance, from a facility for which the credit i s allowed cannot, by itself, support a finding that the techn ology or performance level is adequately demonstrated, but t he information can corroborate an otherwise supported determination or otherwise provide part of the basis for such a

determination. 166 The EPA also proposed to interpret the phrase “with respect to which a credit is allowed under th is section” as referring to the entire phrase “use of technolog y (or level

164 Technical Support Document p. 6. 165 Id. 166 Id. p. 13.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 164 of 786 of emission reduction...) and [] achievement of any e mission reduction..., by or at one or more facilities.” Thus, if technology A received a tax credit, but technology B at the same facility did not, the constraint would not apply to technology

B. 167 Some commenters supported the EPA’s proposed interpretation. Others contended that the EPA’s int erpretation would allow it to support a BSER determination even where EPAct05 facility information comprised 99 percent o f the supporting information for a BSER determination bec ause that determination would not be based “solely” on EPAct0 5 sources. These commenters urged the EPA to conclude that a determination “solely” on the basis of information from EPAct05-a ssisted facilities is any determination where “but for” tha t information, the EPA could not justify its chosen s tandard as

the BSER. 168 Other commenters argued that the provisions bar th e EPA from all consideration of EPAct05 facilities wh en determining that a technology or level of performan ce is adequately demonstrated. In this final rule, the EPA is adopting the interpr etations of all three provisions that it proposed, largely f or the reasons previously advanced. The EPA thus interpret s these

167 Id. p. 14. 168 Comments of AFPM/API p. 46.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 165 of 786 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 of sections 402(i) and 421(a) is consistent with th e views of the only court to date to consider the matter. 169 The EPA notes that the extreme hypothetical posed i n the comments (where the EPA might avoid a limitation on its consideration of EPAct05-assisted facilities by inc luding a mere scintilla of evidence from non-EPAct05 facilities) is not presented here, where the principal evidence that p artial postcombustion CCS is a demonstrated and feasible techn ology comes from sources which received no assistance of any ty pe under

EPAct05. The EPA also concludes that the “but for” test urged by these commenters is an inappropriate reading of the term “solely” in sections 402(i) and 421(a), as any piec e of evidence may be a necessary, or “but for,” cause without bei ng a

169 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 166 of 786 sufficient, or “sole,” cause. 170 Nonetheless, if the “but for” test were applicable here, the available evidence w ould satisfy

it. Other commenters took the extreme position that the EPAct05 provisions bar all consideration of a facility’s ex istence if the facility received EPAct05 assistance. 171 The EPA does not accept this argument because it is contrary to both the plain statutory language 172 (see Chapter 2 of the Response-to-Comment document) and to Congress’s intent that the EPAct05 programs advance the commercialization of clean coal technol ogy. For the same reason, the EPA does not accept some commenter s’ suggestion that sections 402(i), 421(a), and 48A(g) preclude t he EPA from considering NETL’s cost projections for CCS, which base cost estimates on up-to-date vendor quotes reflecting co sts for the

170 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. 171 Supplemental Comments of Murray Energy (comment 94 98) p. 11. 172 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 167 of 786 CCS technology being utilized at the Boundary Dam U nit #3 facility (a facility receiving no assistance under EPAct05), but also considers that to-be-built plants will no long er be firstof-a kind. See generally Section V.I.2 below. Comme nters suggest that the EPAct05 requires that the EPA treat future plants as “first of a kind” when projecting costs, as if EPAc t05 facilities simply did not exist. This reading is co ntrary to the text of the provisions, which as noted, relates spe cifically to a source’s performance and operation (whether a tec hnology is demonstrated, and the level of performance achieved by use of technology), not to sources’ existence. NETL’s cost projections, on the other hand, merely acknowledge the evident f act that CCS technologies exist, and reasonably project that the y will continue to develop. See Section V.I.2. The NETL co st estimates, moreover, are based on vendor quotes for the CCS te chnology in use at the Boundary Dam facility, a Canadian plant which obviously is not a recipient of EPAct05 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 p artial postcombustion CCS is the best system of emission reduc tion 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 168 of 786

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 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 169 of 786 J. Certain Projects Underunder 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 170 of 786 coal-fired power plant in Rogers City, MI. 173 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 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

173 “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 171 of 786 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 existing rather than new sources for purposes of th is rule. 174 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

174 Docket entry: EPA-HQ-OAR-2013-0495-9403

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 172 of 786 site. The developers did not, however, explicitly c haracterize the construction status of the project. 175 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). 176 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 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

175 Docket entry: EPA-HQ-OAR-2013-0495-9599

. 176 “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 173 of 786 construction that has taken place at the proposed P lant Washington site and a recent audit of the project d escribed it

as “dormant”. 177 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 performance at this time because such action may pr ove to be

unnecessary. 178

177 http://www.macon.com/2015/06/23/3811798/audit-sand ersvillecoal-plant.html

. 178 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 174 of 786 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. 179 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 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

is provided in the record for the EPA’s final CAA s ection 111(d) rulemaking. 179 “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 175 of 786 (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. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 176 of 786 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 utili ty power distribution system (that is, to the grid) for sale on an annual basis; (3) be constructed for the purpose of supply ing, and 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 annually depending on the proportion and the amount of electricity actually sold and on the proportion of fossil 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 electric sales criteria that the source be constructed for the purpose of selling more than on e-third of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 177 of 786 their potential electric output and more than 219,0 00 MWh to the grid on an annual basis, regardless of the actual a mount of electricity sold (i.e., we did not include the appl icability criterion that the unit actually sell the specified amount of electricity on an annual basis). In addition, we pr oposed a base load rating criterion that the source be capable of combusting more than 250 MMBtu/h of fossil fuel, regardless of the actual amount of fossil fuel burned (i.e., we did not incl ude the fossil fuel-use criterion that an EGU actually comb ust more than 10 percent fossil fuel on a heat input basis on a 3 -year average). Under this approach, applicability would be known prior to the unit actually commencing operation and would not change on an annual basis. We also proposed that th e final applicability criteria would be consistent for newl y constructed, reconstructed, and modified units. The proposed broad applicability criteria would still not have i ncluded

boilers and IGCC units that were constructed for th e purpose of selling one-third or less of their potential output or 219,000 MWh or less to the grid on an annual basis. These u nits are not covered under subpart Da (the utility boiler and IG CC EGU criteria pollutant NSPS) but are instead covered as industrial boilers under subpart Db (industrial, institutional , and commercial boilers NSPS) or subpart KKKK (the combu stion turbine criteria pollutant NSPS).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 178 of 786 We solicited comment on whether, to avoid implement ation issues related with different interpretations of “c onstructed for the purpose,” the total and percentage electric sales criteria should be recast to be based on permit con ditions. The “constructed for the purpose” language was included in the original subpart Da rulemaking. At that time, the v ast majority of new steam generating units were clearly base loa d units. The “constructed for the purpose” language was intended to exempt

industrial CHP units. These units tend to be relati vely small and were not the focus of the rulemaking. In additi on, units not meeting the electric sales applicability criteria i n subpart Da would be covered by other NSPS so there is limited regulatory incentive, or impact to the environment, for owners /operators to avoid applicability with the utility NSPS. However, for new units, there is no corresponding industrial unit CO 2 NSPS and existing units could debate their original intent ( i.e., the purpose for which they were constructed) in an atte mpt to avoid applicability under section 111(d) requirements. Co nsequently, there could be a regulatory incentive for owners/op erators to

circumvent the CO 2 NSPS applicability. For units that avoid coverage, there would also be a corresponding envir onmental impact. For example, an owner/operator of a new uni t could initially request a permit restriction to limit ele ctric sales to less than one-third of potential annual electric output, but***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 179 of 786 amend the operating permit shortly after operation has commenced to circumvent the intended applicability. Many exis ting units were initially built with excess capacity to accoun t for projected load growth and were intended to sell mor e than onethird of their potential electric output. However, due to various factors (lower than expected load growth, a vailability of other lower cost units, etc.), certain units mig ht have sold less than one-third of their potential electric out put, at least during their initial period of operation. Therefore , the EPA has concluded that determining applicability based on w hether a unit

is “ constructed for the purpose of supplying one-third or more of its potential electric output and more than 219, 000 MWh as net-electric sales” (emphasis added) could create a pplicability uncertainty for both the regulated community and re gulators. In addition, we have concluded that applicability base d on actual operating conditions (i.e., actual electric sales) is not ideal because applicability would not be known prior to d etermining compliance and could change annually. This action finalizes applicability criteria based on design characteristics and federally enforceable pe rmit restrictions included in each individual permit. Ba sed on restrictions, if any, on annual total electric sale s in the operating permit, it will be clear from the time of construction whether or not a new unit is subject to this rule. The***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 180 of 786 applicability includes all utility boilers and IGCC units unless the electric sales restriction 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 approac h is equivalent to, but clearer than, the existing langu age used in subpart Da. In addition, we have concluded that it is important for both the 111(b) and 111(d) requirements for ele ctric-only steam generating units that the permit restriction limiting annual electric sales be included in both the origi nal and current operating permit. Without this restriction, existing units could avoid obligations under state plans dev eloped as part of the 111(d) program by amending their operat ing permit to limit total annual electric sales to one-third of p otential electric output. These units would not be subject t o any GHG NSPS requirements because they would not meet the 1 11(b) or 111(d) applicability criteria and, at this time, th ere is no

NSPS that would cover these units. As described in Section III,

industrial CHP and dedicated non-fossil units also are not

affected 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) has a base load rating greater than 260 GJ/h (250 MMBtu/h ) of fossil fuel (either alone or in combination with any other fuel) and***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 181 of 786 (2) serves a generator capable of supplying more th an 25 MW-net to a utility distribution system (i.e., for sale to the grid). However, we are not establishing final CO 2 standards for certain EGUs. These include: (1) steam generating units and IGCC units that are currently subject to - and have been conti nuously subject to - a federally enforceable permit limitin g annual electric sales to one-third or less of their potent ial electric output (e.g., limiting hours of operation to less t han 2,920 hours annually) or limiting annual electric sales t o 219,000 MWh or less; (2) units subject to a federally enforceab le permit that limits the use of fossil fuels to 10 percent o r less of the unit’s heat input capacity on an annual basis; and (3) CHP units that are subject to a federally enforceable permit condition limiting annual total electric sales to no more tha n their design efficiency times their potential electric ou tput, or to no more than 219,000 MWh, whichever is greater. 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. Accordingly, for purposes of this rule, a newly con structed***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 182 of 786 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 defin ed 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. 180 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). 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

180 40 CFR 60.2, 60.14(e )).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 183 of 786 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. 181 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 In the January 2014 proposal, the EPA proposed that highly efficient new generation technology implementing pa rtial CCS is the BSER for GHG emissions from new steam generatin g EGUs. (See generally 79 FR 1468-1469.) In this final action, t he EPA has determined that the BSER for newly constructed stea m generating units is a new highly efficient supercritical pulve rized coal (SCPC) boiler implementing partial CCS technology t o the extent of removal efficiency that meets a final emission l imitation of

181 40 CFR 60.15.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 184 of 786 1,400 lb CO 2 /MWh-g. The final standard of performance is less stringent than the proposed emission limitation of 1,100 lb

CO 2 /MWh-g. This change, as will be discussed in greate r detail later in this preamble, is in response to public co mments and reflects both a re-examination of the potential BSE R technologies and the most recent, reliable informat ion regarding technology costs. A newly constructed fossil fuel-f ired supercritical utility boiler will be able to meet t he final standard by implementing post-combustion carbon cap ture treating a slip-stream of the combustion flue gas. Alternati ve potential compliance paths are to build a new IGCC unit and c o-fire with natural gas (or use pre-combustion carbon capture o n a slipstream), or for a supercritical utility boiler to c o-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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 185 of 786 (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 standard 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 – 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 at 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 186 of 786 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 g as - 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 187 of 786 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 1,400 lb CO 2 /MWh-g. 79 FR at 1471. However, in that same discussion, the EPA noted the reasons for its reser vations (chiefly reservations about the extent of emission reductions, promotion of advanced CO 2 control technologies, and whether the standard could be met by either utility boilers or IGCC units co-firing with natural gas, or otherwise complying without utilizing partial CCS), and we specifically solicit ed comment on the issue: “We request that commenters who suggest emission***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 188 of 786 rates above 1,200 lb CO 2 /MWh address potential concerns about providing adequate reductions and technology develo pment to be considered BSER.” Id. The proposal thus both solici ted comment on higher emission standards (including 1,400 lb CO 2 /MWh-g based on a less aggressive rate of partial CCS), and prov ided ample notice of the methodology the EPA would use to dete rmine the final BSER and the corresponding final standard. 182 For these reasons, the EPA believes that it provided adequate notice of this potential outcome at proposal, that the final standard of performance was reasonably foreseeable, and that th e final standard is a logical outgrowth of the proposed rul e. 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 pream ble. 183

182 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 understood a matter was under consideration when they addressed it in c omments). 183 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 189 of 786 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. However, as explained below, the final BSER determination an d the scope of modifications to which the final standards apply differ in some important respects from what the EPA proposed. The EPA proposed that the modified unit’s best pote ntial 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

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 captured C O 2 reflected the best available science.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 190 of 786 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 affected steam generating units that implement larger modifications that are consistent with the p roposed BSER

determination for those units. The final standard f or those sources that implement larger modifications is a un it-specific

emission limitation consistent with each modified u nit’s best one-year historical performance (during the years f rom 2002 to the time of the modification), but does not include the additional two percent reduction that was proposed in the January 2014 proposal. In this action, the EPA is not finalizing standards for

those sources that conduct smaller modifications an d is withdrawing the proposed standards for those source s. See***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 191 of 786

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 the efficient steam conditions available, even if the boiler was not or iginally designed to do so). A more detailed discussion of t he rationale

for the BSER determination and the final standards is provided in Section VII 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 Description Final Standard EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review ** * Page 192 of 786

lb CO 2 /MWh-g

New Sources All newly constructed steam generating EGUs 1,400

Modified Sources Sources that implement larger modifications – those resulting in an increase in hourly CO 2 emissions (lb CO 2 /hr) of more than 10 percent Best annual performance (lb CO 2 /MWh-g) 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; small units are those with heat input cap acity of ≤ 2,000 mmBtu/hr. For newly constructed and reconstructed steam gener ating units and for modified steam generating sources tha t result in larger hourly increases of CO 2 emissions, the EPA is finalizing standards in the form of a gross energy output-base d CO 2 emission limit expressed in units of mass per useful energy output, specifically, in pounds of CO 2 per megawatt-hour (lb CO 2 /MWhg). 184 The standard of performance will apply to affected EGUs upon the effective date of the final action.

184 Note that the standards for sources that conduct l arger modifications is a unit-specific numerical standard based on the unit’s best one-year historical performance during the period from 2002 to the time of the modification. The unit -specific standard will also be in the form of a gross energy output-based***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 193 of 786 Compliance with the final standard will be demonstr ated by summing the emissions (in pounds of CO 2 ) for all operating hours in the 12-operating-month compliance period and the n 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 r equires rounding of emission rates with numerical values gr eater than or equal to 1,000 to three significant figures and rou nding of 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 comp liance period option because the final standard of performance fo r newly constructed sources is less stringent than the prop osed standard and because, as discussed in Section V below, we ar e identifying alternative compliance pathways for new steam gener ating EGUs.

CO 2 emission limit expressed in pounds of CO 2 per megawatt-hour (lb CO 2 /MWh-g).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 194 of 786 Specifically, we have concluded that there are unli kely to be significant issues with short-term variability duri ng initial operation, in view of both the reduced numerical st ringency of the standard, and the availability of compliance al ternatives. The EPA notes that co-firing of natural gas can als o serve as an interim means to reduce emissions if a new source o perator believes additional time is needed to phase-in the operation of a CCS system. Therefore, the applicable final stand ards of performance for all newly constructed, modified, an d reconstructed steam generating units must be met ov er a rolling 12-operating-month compliance 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 195 of 786 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 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-g is consistent with the degree of emission reduction achievable through the implementation of the BSER. 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 generating sources t hat addresses

GHG emissions.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 196 of 786 B. Highly Efficient SCPC EGU Implementing Partial C CS as the BSER for Newly Constructed Steam Generating Units In the sections that follow, we explain the technic al configurations that may be used to implement BSER t o meet the final standard, describe the operational flexibilit ies that partial CCS offers, and then provide the rationale for the final standard of performance. After that, we discuss, in greater detail, consideration of the criteria for the deter mination of the BSER. We describe why a highly efficient new SC PC EGU implementing partial CCS in the amount that results in an emission limitation of 1,400 lb CO 2 /MWh-g best meets those criteria, including, among others, that such a syst em is technically feasible, provides meaningful emission reductions, can be implemented at a reasonable cost, does not p ose non-air quality health and environmental concerns or impair energy reliability, and consequently is adequately demonst rated. 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 compliance options that ne w source project developers can elect to use, instead of SCP C with partial CCS, to meet the final standard of performa nce.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 197 of 786

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-g, which a new highly efficient utility boiler burning bituminous coal could have m et by capturing roughly 40 percent of its CO 2 emissions and a new highly efficient IGCC unit could have met by captur ing and storing roughly 25 percent of its CO 2 emissions. The captured CO 2 would then be securely stored in sequestration repo sitories subject to either Class II or Class VI standards un der the Underground Injection Control program. The EPA arri ved at the proposed standard by examining the available CCS im plementation configurations and concluding that the proposed sta ndard at the corresponding levels of partial CCS best balanced t he BSER

criteria and resulted in an achievable emission lev el. The EPA also proposed to find that highly efficient new gen eration implementing “full CCS” (i.e., more than 90 percent capture and storage) was not the BSER because the costs of that configuration – for both utility boilers and IGCC u nits - are projected to substantially exceed the projected cos ts of other non-NGCC dispatchable technologies that utilities a nd project developers are considering (e.g., new nuclear and b iomass). See generally 79 FR at 1477-78. Conversely, the EPA rej ected highly

efficient SCPC as the BSER because it would not res ult in***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 198 of 786 meaningful emission reductions from any newly const ructed PC

unit. Id. at 1470. The EPA also declined to base th e BSER on IGCC operating alone due to the same concern – lack of emission reductions from a new IGCC unit otherwise planned. Id.

2. Basis for the Final Standards For this final action, the EPA reexamined the BSER options available at proposal. Those options are: (1) highl y efficient generation without CCS, (2) highly efficient genera tion implementing partial CCS, and (3) highly efficient generation implementing full CCS. Consistent with our determin ation in the January 2014 proposal, we remain convinced that hig hly efficient generation (i.e., a new supercritical utility boile r or a new IGCC unit) without CCS does not represent the BSER because it does not achieve emission reductions beyond the sec tor’s business as usual, when options that do achieve mor e emission reductions are available. 79 FR 1470; see also Sect ion V.P below. We also do not find that a highly efficient new steam generating unit implementing full CCS is the BSER b ecause, at this time, the costs are predicted to be significan tly more than the costs for implementation of partial CCS and sig nificantly more than the costs for competing non-NGCC base loa d, dispatchable technologies - primarily new nuclear g eneration - and are, therefore, potentially unreasonable. See S ection V.P.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 199 of 786 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 final standard of performance of 1,400 lb

CO 2 /MWh-g is less stringent than at proposal and refle cts changes that are responsive to comments received on, and th e EPA’s further evaluation of, the costs to implement parti al CCS. The EPA has determined that a newly constructed highly efficient supercritical utility boiler burning bituminous coa l can meet this final emission limitation by capturing 16 perc ent of the CO 2 produced from the facility (or 23 percent if burnin g subbituminous or dried lignite), which would be eit her stored in on-site or off-site geologic sequestration reposito ries subject to control under either the Class VI (for geologic sequestration) or Class II (for Enhanced Oil Recove ry) standards under the UIC program. This BSER is technically fea sible, as shown by the fact that post-combustion CCS technolo gy – both the capture and storage components - is demonstrated in full-scale operation within the electricity generating industr y. There are also numerous operating results from smaller-scale projects that are reasonably predictive of operation at full-scal e. It is available at reasonable cost, does not have collate ral adverse non-air quality health or environmental impacts, an d does not have adverse energy implications.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 200 of 786 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. 3. Consideration of Projects Receiving Funding Unde r the EPAct05 As noted in Section III.H.3.g above, the EPA’s

determination of the BSER here includes review of r ecently constructed facilities and those planned or under c onstruction to evaluate the control technologies being used and considered.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 201 of 786 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 th e Department of Energy (DOE), as well as receipt of the Federalfederal tax credit for investment in clean coal technology unde r IRC Section

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, and did not receive the Federalfederal tax credit, is sufficient by itself to support its BSER determi nation. D. Post-Combustion Carbon Capture In this section, we describe a variety of facts tha t support our conclusion that the technical feasibili ty of postcombustion carbon capture is adequately demonstrate d. First, we***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 202 of 786 describe the technology of post-combustion capture. We then describe EGUs that have previously utilized or are currently utilizing post-combustion carbon capture technology . This discussion is complemented by later sections that e xplain and justify our conclusions that the technical feasibil ity of other aspects of partial CCS are adequately demonstrated – namely, the transportation and carbon storage (see Sections V.M . and N). Further, the conclusions of this section are reinfo rced by the discussion in Section V.F. below, in which we ident ify commercial vendors that offer carbon capture techno logy and offer performance guarantees, and discuss industry and technology developers’ public pronouncements of the ir confidence in the feasibility and availability of CCS technolo gies. 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 most combustion processes are at atmospheric pressure and are moved through the flue gas system by fans. The

concentration of CO 2 in most combustion flue gas streams is***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 203 of 786

somewhat dilute. 185 Most post-combustion capture systems utilize liquid solvents 186 that separate the CO 2 from the flue gas in CO 2 scrubber systems. Because the flue gas is at atmosp heric pressure and is somewhat dilute, the solvents used for postcombustion capture are ones that separate the CO 2 using chemical absorption (or chemisorption). Amine-based solvents 187 are the most commonly used in post-combustion capture syste ms. In a chemisorption-based separation process, the flue ga s 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 high purity CO 2 stream. This heating step is referred to as “solve nt regeneration” and is responsible for much of the “e nergy penalty” of the capture system. Steam from the boil er (or potentially from another external source) that woul d otherwise be used to generate electricity is instead used in the solvent regeneration process. The development of advanced s olvents – those that are chemically stable, have high CO 2 absorption capacities, and have low regeneration energy requir ements – is an active area of research. Many post-combustion so lvents will

185 The typical concentration of CO 2 in the flue gas of a coalfired utility boiler is roughly around 15 volume pe rcent. 186 A solvent is a substance (usually a liquid) that dissolves a solute (a chemically different liquid, solid or gas), res ulting in a solution. 187 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 204 of 786 also selectively remove other acidic gases such as sulfur dioxide ( SO 2 ) and hydrochloric acid (HCl), which can result in degradation of the solvent. For 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 in some cases, the ac idic gases will need to be scrubbed to very low levels prior t o the flue gas entering the CO 2 capture system. See also RIA chapter 5 (quantifying SO 2 reductions resulting from this scrubbing process). Additional information on post-combustion carbon ca pture – including process diagrams - can be found in a summ ary technical support document. 188 2. Post-combustion Carbon Capture Projects that hav e not Received DOE Assistance through the EPAct05 or Tax Credits under

IRC Section 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

188 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 205 of 786 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 tha n expected.” 189,190 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 facility is producing more power than predicted and that the energy penalty (parasitic load – the energy needed to regenerate

the CO 2 capture solvent) is much lower than initially predicted. 191 Water use at the facility is consistent with level s

189 “[W]e are achieving better than expected” operatio n out of the plant, SaskPower's Mike Marsh said April 8, 201 5 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). 190 “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 //. 191 Correspondence between Mike Monea (SaskPower) and Nick Hutson (EPA), February 20, 2015.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 206 of 786 that were predicted. 192 The total project costs – for the power plant and the carbon capture plant – was $1.467B (C AD). 193 The CO 2 from the capture system is more than 99.999 percent pure with only trace levels of N 2 in the product stream. 194 This purity is food-grade quality CO 2 and is a clear indication that the system is working well. The captured CO 2 is transported by pipeline to nearby oil fields in southern Saskatchewan where it is being used for 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 demonstrate that such a system could be utilized at a much larger utility c oal-fired boiler. However, there is nothing to indicate that the post-

192 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. 193 About $1.2B USD; roughly $700M (USD) for the carbo n capture system, which was on budget. 194 “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 207 of 786 combustion system used at Boundary Dam could not be scaled-up for use at a larger utility boiler. In fact, the ca rbon capture system at Boundary Dam #3 is designed and construct ed 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 capture system – with no need for further scale-up - could be used to treat a slip-stream of a much larger superc ritical utility boiler (a new unit of approximately 500 to 600 MW) in order to meet the final standard of performance of 1,400 lb

CO 2 /MWh-g, which would only require partial CCS on the order of approximately 16 to 23 percent (depending on the co al used). A “slip-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 gas from a c oal-fired boiler to be separated into two or more streams and treated separately in different control equipment before be ing

recombined to exit from a common stack. 195 A slip-stream configuration is often used to treat a smaller port ion of the bulk flue gas stream as a way of testing or demonst rating a control device or measurement technology. For imple mentation of post-combustion partial carbon capture, a portion o f the bulk flue gas stream would be treated separately to capt ure

195 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 208 of 786 approximately 90 percent of the CO 2 from that smaller slip-stream of the flue gas. For example, in order to capture 2 0 percent of

the CO 2 produced by a coal-fired utility boiler, an operat or would treat approximately 25 percent of the bulk fl ue gas stream (rather than treating the entire stream). Approxima tely 90 percent of the CO 2 would be captured from the slip-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 slipstream approach was the most economical for carbon capture of less than 90 percent of the total CO 2 . 196 The advantage of the slip-stream approach is that the capture system wil l be sized to treat a lower volume of flue gas flow, which reduce s the size of

the CO 2 absorption columns, induced draft fans, and other equipment, leading to lower capital and operating c osts. The carbon capture system at Boundary Dam does not utilize the slip-stream configuration because it was design ed to achieve more than 90 percent capture rates from the 110 MW facility.

196 “Cost and Performance of PC and IGCC for a Range o f Carbon Capture”, Rev 1 (2013), DOE/NETL-2011/1498 p. 2 (“A literature search was conducted to verify that <90 percent CO 2 capture is most economical using a ’slip-stream’ (or bypass) a pproach. Indeed, the slip-stream approach is more cost-effec tive for <90 percent CO 2 capture than removing reduced CO 2 fractions from the entire flue gas stream, according to multiple peer- reviewed studies.” See also id. at 19, 21, 77, and 478 (docu menting further that treating a slip-stream is the most eco nomical approach).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 209 of 786 However, the same carbon capture equipment could be used to treat approximately 50 percent of the flue gas from a 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 Boundary Dam p lant can be utilized for partial carbon capture at a much large r 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 and indeed, the late st NETL cost estimates assume that the capture technology would be used in a new unit using bituminous coal. 197 The EPA is unaware of any reasons why the Boundary Dam technology would not b e transferrable to another utility boiler at a differ ent location

at a different elevation or climate because the con trol technology is not climate or elevation-dependent.

197 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 210 of 786 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 p ostcombustion 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 211 of 786 (CFB) coal-fired power plants with carbon capture a mine scrubbers developed by ABB/Lummus. The scrubbers we re designed to process a slip-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 bitumino us and subbituminous coals, CO 2 from an approximate 5 percent slipstream (about 66,000 metric tons of CO 2 per year) has been captured since 2001. The captured CO 2 from the Shady Point Plant is also sold for use in the food processing industr y. 198 While these projects do not demonstrate the CO 2 storage component of CCS, they clearly demonstrate the technical viabili ty of partial

CO 2 capture. The capture of CO 2 from a slip-stream of the bulk flue gas, as described earlier, is the most economi cal method for capturing less than 90 percent of the CO 2 . The amounts of partial capture that these sources have demonstrate d – up to 10 percent – is reasonably similar to the level, at 16 to 23 percent, that the EPA predicts would be needed by a new highly efficient steam utility boiler to meet the final st andard of

198 Dooley, J. J., et al. (2009). “An Assessment of th e Commercial Availability of Carbon Dioxide Capture a nd Storage Technologies as of June 2009”. U.S. DOE, Pacific No rthwest National Laboratory, under Contract DE-AC05-76RL018 30.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 212 of 786 performance. These facilities, which have been oper ating for multiple years, clearly show the technical feasibil ity of postcombustion 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 capture 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. 199 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. 200 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

199 IEA (2009), World Energy Outlook 2009, OECD/IEA, P aris. 200 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. 34 below.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 213 of 786 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 the

CO 2 ) has been reduced by about 5 times from the amine process originally used at the Searles Valley facility. The amine scrubbing process used at Boundary Dam is equally e fficient, and the amine scrubbing system to be used at the Petra Nova WA Parish project (Thompsons, TX) is projected to be a s well. 201

3. Post-combustion carbon capture projectsCarbon Capture Projects that receivedReceived DOE assistanceAssistance through the EPAct05, but did not receive tax creditsReceive Tax Credits

under IRC Section 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

201 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 214 of 786 support that CCS has received from vendors and othe rs (described below) to adequately demonstrate that post-combusti on 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 that does not disqual ify 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 o f 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 slip-stream of the 610 MW WA Parish facility. The project is expec ted to be operational in 2016 and thus does not yet directly demonstrate the technical feasibility or 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 sl ipstream demonstration and received DOE Clean Coal Po wer Initiative (CCPI) funding (as provided in EPAct05) on that basis. The developers later expanded the project to the larger***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 215 of 786 240 MW slip-stream because of the need to capture g reater

volumes of CO 2 for EOR operations. No additional DOE or other federal funding was obtained for the expansion from a 60 MW slip-stream to a 240 MW slip-stream. 202 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, 203 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 c an use coal to sustain our energy ecosystem while we b egin reducing our carbon footprint. According to NRG, the Petra Nova Carbon Capture Pro ject will utilize “a proven carbon capture process,” joi ntly developed by Mitsubishi Heavy Industries, Ltd. (MHI ) and the

202 Thus, even if 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 considered a DOE-assisted proj ect. In any case, as described above, even without consideratio n of this facility at all, other information adequately demon strates the technical feasibility of post-combustion CCS. 203 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 216 of 786 Kansai Electric Power Co., that uses a high-perform ance solvent

for CO 2 absorption and desorption. 204 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. WA Parish Unit #8 came on-line in 1982 and is thus an existing source that will no t be subject to final standards of performance issued in this ac tion. However, because it will be capturing roughly 35 pe rcent of the

CO 2 generated by the facility, its emissions will be b elow the final new source emission limitation of 1,400 lb CO 2 /MWh-g. 205 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.

204 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. 205 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 217 of 786 The carbon capture system at WA Parish will utilize a slipstream configuration. However, as noted, the system is designed to capture roughly 35 percent of the CO 2 from WA Parish Unit #8 (90 percent of the CO 2 from the 240 MW slip-stream from the 610 MW unit). A carbon capture system of the same size as that used at WA Parish could be used to treat a 240 MW slip-s tream from a 1,000 MW unit in order to meet the final standard o f performance of 1,400 lb CO 2 /MWh-g. Again, the experience at the WA Parish Unit #8 proj ect will be directly transferable to post-combustion capture at a new utility boiler, even though WA Parish Unit #8 is an existing source that has been in operation for over 30 years . In fact, retrofit of such technology at an existing unit can be more challenging than incorporating the technology into the design of a new facility. The experience will be directly tra nsferrable to other types of post-combustion sources including th ose using different boiler types and those burning different coals. The amine scrubbing and associated systems are not boil er type- or coal-specific. The EPA is unaware of any reasons th at the technology utilized at the WA Parish plant would no t be transferrable to another utility boiler at a differ ent location at a different elevation or climate, given that the technology is not dependent on either climate or topography.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 218 of 786 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 slip-stream of the p lant’s exhaust flue gas. In May 2011, Alstom Power announc ed the successful operation of the chilled ammonia CCS val idation 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 operation, including load changes, and saw an avail ability of the CCS system of greater than 90 percent. 206 AEP, with assistance from the DOE, had planned to e xpand the slip-stream demonstration to a commercial scale , fully integrated demonstration at the Mountaineer facilit y. 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

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

sequestration-ccs-project //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 219 of 786 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, but did not express do ubts about the feasibility of the technology. See Section V.L below. AEP also prepared a Front End Engineering & Design (FEED) Report, 207 explaining in detail how its pilot-scale work coul d be scaled up to successful full-scale operation, and t o accommodate the operating needs of a full-scale EGU, including 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. 208 See Section V.G.3 below,

207 “CCS front end engineering & design report: Americ an Electric Power Mountaineer CCS II Project. Phase 1”, pp 10-1 1; available at: http://www.globalccsinstitute.com/publications/ aepmountaineer-ii-project-front-end-engineering-and-de sign-feedreport 208 Id. at 11. The EPA does not view this information as being affected by the constraints in EPAct05. The informa tion does not***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 220 of 786 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 CDR Process, which uses a proprietary high performi ng solvent 209

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

CO 2 has been transported via pipeline approximately 12 miles to the Citronelle oil field where it is injected into the Paluxy formation, a saline reservoir, for storage. 210

relate to use of technology, level of emission redu ction 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 enginee ring challenges which would remain at full scale and how those challenges can be addressed. 209 This is the same carbon capture system that is bei ng utilized at the Petra Nova project at the NRG WA Parish plan t. 210 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 221 of 786 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.” 211 E. Pre-Combustion Carbon Capture As described earlier, the EPA does not find that IG CC technology – either alone or implementing partial C CS – 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 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

211 Id.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 222 of 786 (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 – howCarbon Capture – How it

worksWorks 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 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 HRSG and steam turbine). Th e gasification process also typically produces some a mount of CO 2 212

212 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 223 of 786 as a by-product along with other gases (e.g., H 2 S) and inorganic materials originating from the coal (e.g., minerals , ash). The

amount of CO 2 in the syngas can be increased by “shifting” the composition via the catalytic water-gas shift (WGS) reaction. This process involves the catalytic reaction of ste am (“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. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 224 of 786 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. 213

2. Pre-combustion carbon capture projectsCarbon Capture Projects

that have not receivedReceived DOE assistanceAssistance through

EPAct05 or tax creditsTax Credits under IRC Section 48A a. Dakota Gasification Great Plains Synfuels Plant

. Each day, the Dakota Gasification Great Plains Synf uels Plant uses approximately 18,000 tons of North Dakot a lignite in a coal gasification process that produces syngas (a mixture of carbon monoxide, carbon dioxideCO, CO 2 , and hydrogenH 2 ), which is then converted to methane gas (synthetic natural ga s) using a methanation process. Each day, the process produces an average of 145 million cubic feet of synthetic natural gas that is ultimately transported for use in home heating and electricity generation. 214 Capture of CO 2 from the facility began in 2000. The Synfuels Plant, using a pre-combustion Rectisol® process, ca ptures about

3 million tons of CO 2 per year - more CO 2 from coal conversion than any facility in the world, and is a participan t in the

213 Technical Support Document – “Literature Survey of Carbon Capture Technology”, available in the rulemaking do cket (Docket ID: EPA-HQ-OAR-2013-0495). 214 http://www.dakotagas.com/Gasification //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 225 of 786 world's largest carbon sequestration project. On av erage about 8,000 metric tons per day of captured CO 2 from the facility is sent through a 205-mile pipeline to oil fields in S askatchewan, Canada, where it is used for EOR operations that re sult in permanent CO 2 geologic storage. The geologic sequestration of CO 2 in the oil reservoir is monitored by the Internatio nal 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 EGU, t hat 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 operations to meet cyclic electricity generation de mands. In the January 2014 proposal, the EPA had noted that, whil e the facility is not an EGU, it has significant similari ties to an IGCC and the implementation of the pre-combustion c apture 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 carbon monoxide ( CO ), hydrogen (, H 2 ), and

some amount of CO 2 (depending on the gasifier and the specific operating conditions). A water-gas-shift reaction u sing water***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 226 of 786 (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 comb usting the un-shifted syngas in a conventional combustion turb ine. If the syngas is shifted such that the resulting 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 upo n the level of capture required. 215 The Dakota Gasification process bears essential similarities to the just-described IGCC gasificatio n system. As 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, only the manner in which the syng as is used distinguishes the IGCC gasification system from the Dakota Gasification facility. In the IGCC process, the syn gas is combusted. In the Dakota Gasification facility, the syngas is processed through a catalytic methanation process w here the CO

215 “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 227 of 786

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. 216 b. International projects

. There are some international projects that are in v arious stages of development that indicate confidence by d evelopers in the technical feasibility of pre-combustion carbon 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 for sequestration in a saline form ation in the North Sea. The U.K. Department of Energy & Climate Change (DECC)

216 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 228 of 786 recently announced funding to allow for feasibility studies for this plant. 217 Commercial operation is expected in 2017. 218 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 pre-combustion capture technology. The captured CO 2 will be used for EOR operations. 219 Vattenfall and Nuon’s pilot project in Bugennum, Th e Netherlands involves carbon capture from coal- and biomass-fired IGCC plants. It has operated since 2011. 220 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. 221

217 http://www.downstreambusiness.com/item/Summit-Powe r-WinsFunding-Studies-Proposed-IGCC-CCS-Project_140878

. 218 http://www.summitpower.com/projects/carbon-capture //. 219 http://sequestration.mit.edu/tools/projects/greeng en.html

. 220 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 ).. 221 Puertollano Fact Sheet: Carbon Dioxide Capture and Storage Project, Carbon Capture & Sequestration Technologie s @ MIT, https://sequestration.mit.edu/tools/projects/puerto llanto.html (last visited )..***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 229 of 786 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. 222 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. 223 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.

222 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 . and https://www.globalccsinstitute.com/projects/large-s cale-ccsprojects. 223 Utmaniyah CO 2 EOR Demonstration Project, Global CCS Institute, http://www.globalccsinstitue.com/project/uthmaniyah -co2-eordemonstration-project-0.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 230 of 786

3. Pre-combustion carbon capture projectsCarbon Capture Projects

that have receivedReceived DOE assistanceAssistance through EPAct05, but did not receive tax creditsReceive 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 231 of 786 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.

4. Pre-combustion carbon capture projectsCarbon Capture Projects

that have receivedReceived DOE assistanceAssistance through

EPAct05 and tax creditsTax Credits under 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 232 of 786 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) 224

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 IGC C 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

224 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 233 of 786 that they expect to commence construction on the pr oject in

2015. 225 The facility will utilize the Linde Rectisol® gas cleanup process to capture carbon dioxide 226 – the same process that has been deployed for decades, including at th e Dakota Gasification facility, a clear indication of the de veloper’s confidence in that technology and further evidence that the Dakota Gasification carbon capture technology is tr ansferable to

EGUs. 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.

1. Performance guaranteesGuarantees

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

225 “Odessa coal-to-gas power plant to break ground th is year”, Houston Chronicle (April 1, 2015). 226 http://www.texascleanenergyproject.com/project //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 234 of 786 Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 440 (D.C. Cir. 1973), the Court upheld standards of performance fo r coal-fired steam generators based on “prototype testing data a nd full-scale control systems, considerations of available fuel s upplies, literature sources, and documentation of manufacturer guarantees and expectations ”(emphasis supplied)). 227 Subsequently, in Sierra Club v. Costle, the Court noted, in upholding the standard: “we find it informative that the vendors of FGD equipme nt corroborate the achievability of the standard.” 228 Linde and BASF offer performance guarantees for car bon capture technology. The two companies are jointly m arketing new, advanced technology for capturing CO 2 from low pressure gas streams in power or chemical plants. In product lit erature, 229 they note that Linde will provide a turn-key carbon capture

227 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.”). 228 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”). 197 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 235 of 786 plant using a scrubbing process and solvents develo ped by BASF, one of the world’s leading technical suppliers for gas treatment. 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 ... 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 carbon capture. For example, Fluor h as developed patented CO 2 recovery technologies to help its clients reduce G HG emissions. The Fluor product literature 230 specifically points to

the Econamine FG Plus SM (EFG+) process, which uses an amine solvent to capture and produce food grade CO 2 from postcombustion sources. The literature further notes th at EFG+ is

230 www.fluor.com/client-markets/energy-chemicals/Page s/carboncapture.aspx

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 236 of 786 also used for carbon capture and sequestration proj ects, that the proprietary technology 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 po wer plant's unique site requirements, 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. 231 The article notes, “Technology for the removal of carbon dioxide (CO 2 ) from flue gas streams has been around for quite some time. The technology was developed not t o address the GHG effect but to provide an economic source of CO 2 for use in enhanced oil recovery and industrial purposes, 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 .

231 http://www.powermag.com/commercially-available-co2 -capturetechnology //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 237 of 786 In addition, Shell has developed the CANSOLV CO 2 Capture System, which Shell describes in its product litera ture 232 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 GHG abatement r egulations by removing CO 2 from their exhaust streams, with the added benefit of simultaneously lowering SO 2 and NO 2 emissions. 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. 233 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

232 http://www.shell.com/global/products-services/solu tions-forbusinesses/globalsolutions/shell-cansolv/shell-cans olvsolutions/co2-capture.html

. 233 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 238 of 786 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 it is unlikely that a single technology vendor woul d provide a guarantee for “the system as a whole.”

2. Academic and other literatureOther Literature Climate change mitigation options – including CCS - are the subject of great academic interest, and there is a large body of academic literature on these options and their tech nical feasibility. In addition, other research organizati ons (e.g., U.S. national laboratories and others) have also pu blished studies on these subjects that demonstrate the avai lability of these technologies. A compendium of relevant litera ture is provided in a Technical Support Document available in the rulemaking docket. 234

234 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 239 of 786

3. Additional statementsStatements by technology developersTechnology 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 Section 48A tax credit. These statements provide fu rther, although not necessary, support. For example, Southern Company’s Mississippi Power h as stated that, because the SelexolTM process has been used in industry for decades, 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. 235 And ... The carbon capture equipment and processes proposed in this project have been in commercial use in the

235 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 240 of 786 chemical industry for decades and pose little techn ology risk. 236 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 storage is in fact viable technology for the United States and quite honestly for the rest of the world going forward. 237 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). 238 As discussed above, vendors do in fact offer perfor mance guarantees. We further note that, as noted above, B oundary Dam Unit #3 is a full-scale project that is successfull y implementing full CCS with post-combustion capture, and Dakota

236 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. 237 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. 238 Alstom Comments, p. 3.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 241 of 786 Gasification is likewise a full-scale commercial op eration that is successfully implementing pre-combustion CCS tec hnology. Moreover, as we explain above, this technology and performance is transferable to the steam electric generating se ctor. In addition, as noted above, technology providers and technology end users have expressed confidence in the availabi lity and performance of CCS technology. 239 G. Response to Key Comments on the Adequacy of the Technical Feasibility Demonstration

1. Commercial availabilityAvailability

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 pro posal, the D.C. Circuit has explained that a standard of perfo rmance is “achievable” if a technology or other system of emi ssion

239 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 242 of 786 reduction can reasonably be projected to be availab le 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. In any case, as discussed above, CCS technology is availab le through vendors who provide performance guarantees, which i ndicates that in fact, CCS is commercially available, which adds to the evidence that the technology is adequately demonstr ated to be technically feasible. In sum, “[t]he capture and CO 2 compression technologies have commercial operating experience w ith demonstrated ability for high reliability.” 240 2. Must a technology or system of emission reductio n 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

240 “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 243 of 786 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.

2d at 401-02. 241 In a related argument, other commenters stated that a system cannot be adequately demonstrated unless all of its component parts are operating together. 242 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 in tegrated at Boundary Dam: post-combustion full CCS is being uti lized at a

241 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 ag ency 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.91-1196, 91 st Cong., 2d Sess. 16 (1970). 242 See, e.g., Comments of UARG p. 5.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 244 of 786 steam electric fossil fuel-fired plant, with captur ed carbon 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 pilotPilot and demonstration projectsDemonstration 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 245 of 786 that data from pilot-scale, or less than full-scale operation, can be shown to reasonably demonstrate performance at full-scale 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. 243 The EPA

has done so here. Most obviously, the final standard reflects experie nce of full-scale operation of post-combustion carbon capt ure. Precombustion carbon capture is likewise demonstrated at fullscale. Second, the record explains in detail how CC S can be implemented at full-scale. The NETL cost and perfor mance 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

243 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 246 of 786 capture CO 2 : coal and sorbent receiving and storage, steam generator and ancillaries, NO X control system, particulate 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. 244 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. Tenaska Trailblazer Partners, LLC also prepared a F EED study 245 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

244 Cost and Performance Baseline for Fossil Energy Pl ants Volume 1: Bituminous Coal and Natural Gas to Electricity; Revision 2a, pp. 57-74. 245 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 247 of 786 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. Som e commenters argued that the EPA minimized – or even ignored – t hese publically voiced concerns in the discussion presen ted in the January 2014 proposal. On the contrary, the EPA has not minimized or ignored these complexities, but it is important to

realize that most of these statements come in a dif ferent context: namely, implementing full CCS, or retrofit ting CCS onto existing power plants. For example, in the Final Re port of the President’s CCS Task Force, it was noted that “inte gration of CCS technologies with the power cycle at generating plants can present significant cost and operating issues that will need to be addressed to facilitate widespread, cost-effecti ve deployment***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 248 of 786

of CO 2 capture.” 246 This statement – and most of the statements in this vein – are in reference to implementation of f ull CCS systems that capture more than 90 percent of the CO 2 and many reference widespread implementation of such technol ogy. The EPA has addressed the concerns regarding “significant c ost” by finalizing a standard that relies on partial CCS wh ich we show, in this preamble and in the supporting record, can be implemented at a reasonable, non-exorbitant cost. T he Boundary Dam facility, in particular, demonstrates that the complexities of implementing CCS – even full CCS – can be overco me. 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. Implementation of CCS at some existing sources may be

246 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 28. See also DOE Carbon Capture Website: “First generation CO 2 capture technologies are currently being used in various industrial applications. How ever, in their current state of development, these technolog ies are not ready for implementation on coal-based power plants because they have not been demonstrated at appropriate scale, re quisite approximately one-third of the plant’s steam power to operate, and are cost prohibitive.” (Dec 2010); and Testimon y of Dr. S. Julio Friedmann, Deputy Asst. Secretary of Energy f or Clean Coal, US Dept. of Energy, before the Subcommittee o n Oversight and Investigations Committee on Energy and Commerce (Feb. 11, 2014): CCS technologies at new coal-fired plants wo uld result in "something like a 70 to 80 percent increase on the wholesale price of electricity."***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 249 of 786 challenging because of space limitations. That shou ld not be an issue for a new facility because the developer will need to ensure that adequate space is available during the design of the facility. Constructing CCS technology at an existin g 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 existing equipment at t he plant. Some commenters noted the challenges of diverting s team from the plant’s steam cycle. Again, that is primarily an is sue with full CCS implementation as a retrofit to an existing sou rce. Consideration of steam requirements for solvent reg eneration can be factored into the design of a new facility. We a lso note that issues of integration with the plant’s steam cycle are less challenging when implementing partial 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 250 of 786 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 op eration, 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 EPA has more evidence here, as the baghouse standar d in Sierra

Club was justified based largely on less-than-full-scal e operation. See 657 F. 2d at 380 (there was only “limited data from one full scale commercial sized operation”), 3 76 (“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 red uction.”***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 251 of 786

Based on consideration of relevant cost metrics in the context of current market conditions, the EPA concludes tha t the costs

associated with the final standard are reasonable. In reaching this determination, the EPA considered a host of different cost metrics, each of which illuminate d a particular aspect of cost consideration, and each o f which

demonstrated that the costs of the final standard a re reasonable. The EPA evaluated capital costs on a pe r-plant basis, responding to public comment that noted the particular significance of capital costs for coal-fired EGUs. As in the proposal, the EPA also considered how the standard would affect

the LCOE for individual affected EGUs as well as na tional, overall cost impacts of the standard. The EPA found that the anticipated cost impacts are similar to those in ot her promulgated NSPS – including for this industry - th at have been upheld by the D.C. Circuit. The costs are also comp arable to those of other base load technologies that might be selected on comparable energy portfolio diversity grounds. Fina lly, the EPA does not anticipate any significant overall nationw ide costs or cost impacts on consumers because projected new gen erating capacity is expected to meet the standards even in the baseline. Accordingly, after considering costs from a range o f different perspectives, the EPA concludes that the costs of t he final

standard are reasonable.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 252 of 786

1. Rationale at proposalProposal At proposal, the EPA evaluated the costs of new coa l-fired EGUs implementing full (90 percent) and partial CCS . The EPA compared the predicted LCOE of those units against the LCOE of other new dispatchable technologies often considere d 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 imp lementing full CCS was higher than that of the other non-NGCC dispatchable technologies, and we did not propose to identify a new steam EGU implementing full CCS as BSER on that basis. Id. at 1477. The EPA proposed that a standard of performance of 1,10 0 lb CO 2 /MWhg, reflecting a new steam EGU implementing partial CCS, could be achieved at reasonable cost based on a comparison o f the projected LCOE associated with achieving this stand ard with the alternative dispatchable technologies just mentione d. 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. 247 The EPA used LCOE

247 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 253 of 786 projections for non-fossil dispatchable generation – specifically nuclear and biomass – from the EIA AEO 2013. See 79

FR 1435. In addition, the EPA proposed that the costs to imp lement partial CCS were reasonable because a segment of th e industry was already accommodating them. Id. at 1478. The EPA also considered anticipated decreases in the cost of 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 EOR. Id. at 1478- 80. The EPA noted that the proposed standard was no t expected to lead to any significant overall costs or effects on electricity prices. Id. at 1480-81. The EPA also acknowledged the overall market context, noting that fossil steam EGUs, even without any type of CCS, are significantly more expensive than new natural gas-fired electricity generation, but that some ele ctricity suppliers might include new coal-fired generating s ources in their generation portfolio, and would pay a premium to do so.

Id. at 1478.

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 254 of 786

2. Brief summarySummary of cost considerationsCost

Considerations under 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 cost consideration. In addition, it should be noted that in evaluating the reasonableness of costs, the D.C. Ci rcuit has upheld application of a variety of metrics, such as the amount of control costs or product price increases. See Se ction 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 contextContext The EIA projects that few new coal-fired EGUs will be constructed over the coming decade and that those t hat are built will apply CCS, reflecting the broad consensus of g overnment,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 255 of 786 academic, and industry forecasters. 248 The primary reasons for this projected trend include low electricity demand growth, highly competitive natural gas prices, and increase s in the supply of renewable energy. In particular, U.S. ele ctricity demand growth has followed a downward sloping trend for decades with future growth expected to remain very low. 249 Furthermore, the EPA projects that, for any new fossil fuel-fire d electricity generating capacity that is constructed through 203 0, natural gas will be the overwhelming fuel of choice. 250 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

248 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 2 015,” DOE/EIA-0383(2015), April 2015, “[v]ery little unpl anned coalfired capacity is added across all the AEO 2015 cas es”, p. 26. 249 EIA, “Annual Energy Outlook 2015,” DOE/EIA-0383(20 15), April 2015, p. 8. 250 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 256 of 786 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 coal- fired generating capacity is not anticipated in the near term, even in the absence of the standards of performance 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.” Fuel 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 251 notes examples where the goal of fuel diversity was considered in IRPs; in many cases, th ese plans

251 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 257 of 786 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. In addition, the EPA recognizes that there may be i nterest in constructing a new combined-purpose coal-fired f acility that would generate power as well as produce chemicals o r CO 2 for use in EOR projects. These facilities would similarly p rovide

additional value due to the revenue streams from sa leable chemical products or CO 2 . 252 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 and rejects more str ingent options that would impose potentially excessive cos ts. In fact, based on this careful consideration of costs, the E PA is finalizing a substantially lower cost standard than the one we proposed. At the same time, we note the unusual cir cumstances 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

252 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. See 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 258 of 786 chapter 4 (documenting that electric power companie s will choose to build new EGUs that comply with the regulatory r equirements 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. 253 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. 254 This cost-reasonable standard will preserve the opportunity for such projects while driving new tec hnology deployment. 255

253 See, e.g., Comments of Murray Energy, pp. 79-80. 254 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. 255 In this rulemaking, our determination that the cos ts are reasonable means that the costs meet the cost stand ard in the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 259 of 786

4. Consideration of capital costsCapital Costs As noted above, CAA section 111 does not mandate a ny 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 and, as discussed further below, the LCOE metric re lied upon at proposal and in this final rulemaking incorporates and fully reflects capital costs. 256 Nonetheless, extensive comment from industry representatives and others noted persuasiv ely that fossil-steam units are very capital-intensive proje cts and recommended that a separate metric, solely of capit al costs, be considered by the EPA in evaluating the final stand ard’s costs. Accordingly, the EPA has considered the final standard’s impact on the capital costs of new fossil-steam generation . The EPA has determined that the incremental capital costs of th e final standard are reasonable because they are comparable to those in prior regulations and to industry experience, and b ecause the

case law no matter how that standard is articulated , thisthat is, whether the cost standard is articulated throug h the terms that the case law uses, e.g., “exorbitant,” “excess ive,” etc., or through the term we use for convenience, “reason ableness.” 256 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 260 of 786 fossil steam electric power industry has been shown to be able to successfully absorb capital costs of this magnit ude 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 EGUs were $1 9M for a 600 MW plant, consisting of $3.6M for particulate matte r controls, $14.4M for sulfur dioxide controls, and $1M for nit rogen oxides controls, representing a 15.8 percent increase in c apital costs above the $120M cost of the plant. See 1972 Supplem ental 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 were reasonable, concluding that the EPA had properly taken costs into consideration. Essex Cement v.

EPA , 486 F. 2d at 440. In reviewing the 1978 NSPS for coal-fired EGUs, the D.C. Circuit recognized that “EPA estimates that utiliti es will have to spend tens of billions of dollars by 1995 on pol lution control under the new NSPS” and that “[c]onsumers w ill ultimately bear these costs.” Sierra Club , 657 F.2d at 314. The court nonetheless upheld the EPA’s determination that the

standard was reasonable. Id. at 410.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 261 of 786 The cost and investment impacts of the 1978 NSPS on electric utilities were subsequently evaluated in a 1982 Congressional Budget Office (CBO) retrospective stu dy. 257 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. 258 The study further noted that air pollution control requirements in general had l ed to an estimated 37.5 to 45 percent increase in capital co sts for coalfired power plant installation between 1971 and 198 0. 259 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.” 260 In assessing the capital cost impacts of the suite of 1970s 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.” 261

257 Congressional Budget Office report, “The Clean Air Act, the Electric Utilities, and the Coal Market”, April 198 2, p. 10-11, 23. 258 Id. at 10-11. 259 Id. at 22. 260 Id. at xvi. 261 Id.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 262 of 786 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 comparable in magnitude on an individ ual unit basis to those projected for the present standard. We predict that the incremental costs of control for a new hig hly efficient

SCPC unit to meet the final emission limitation of 1,400 lb

CO 2 /MWh-g would be an increase of 21 - 22 percent for capital

costs. See Table 7 below. 262,263

262 We explain at Section V.I.2 and 3 below the reason ableness of the EPA’s cost projections here. 263 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 263 of 786 Table 7. Comparison of estimated capital costsEstimated Capital Costs for a newNew SCPC and a newNew SCPC meetingMeeting the final standardFinal Standard of performancePerformance

. 264

Total Total Overnight As-Spent Cost Capital (2011$/kW) (2011$/kW)

SCPC - no CCS 2,507 2,842 SCPC - partial CCS 3,042 3,458 (1,400 lb CO 2 /MWh-g)

Incremental cost increase 21.3% 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.

5. Consideration of costs basedCosts Based on levelized

costLevelized Cost of electricityElectricity 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

“Achievability of the Standard for Newly Constructe d Steam Generating EGUs” technical support document availab le in the rulemaking docket. 264 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 264 of 786

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 express es the full 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-in tensive 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 proposal. 265 The updated SCPC cases in the reports include up-t o-

265 “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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 265 of 786 date 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. 266 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). 267 The EIA also updated LCOE projections from 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

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

. 266 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. 267 “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 http://www.netl.doe.gov/research/energy-analysis/en ergybaseline-studies.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 266 of 786 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. 268 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 the 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

. 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

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

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 267 of 786 to finance the project, and finally on the assumed capacity

factor. 269 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 whol esale electricity price, can vary seasonally and over the course of a day. In addition, electricity generation technologi es differ on dimensions other than just cost, such as ramping ef ficiency, intermittency, or uncertainty in future fuel costs. These other factors are also important in determining the value of a particular generation technology to a firm, and acc ordingly cost

269 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 268 of 786 comparisons between two different technologies are most appropriate and insightful when the technologies al ign along these other dimensions. Isolating a comparison of technologies based on their LCOE is appropriate when they can be assumed to provide similar services and similar values of elec tricity generated. As we indicated in the proposal, we evaluated publi cly available IRPs and other available information (suc h as public announcements) to determine the types of technologi es that utilities are considering as options for new genera ting capacity. 270 In the near future, the largest sources of new fossil fuel-fired power generation are expected to be new NGCC units. But the IRPs also suggested that utilities a re interested in a range of technologies that can be used to prov ide or preserve fuel diversity within the utilities’ respe ctive

270 See also discussion at V.C.3 above. The IRPs do no t 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 269 of 786 generating fleets. 271,272 The options for dispatchable generation that can provide intermediate or base-load power an d fuel

271 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 270 of 786 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 IRP - https://www.dom.com/library/domcom/pdfs/corporate/i ntegratedresource-planning/va-irp-2014.pdf

.

272 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 271 of 786 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 ramped up or down as needed, e.g., coal-fired units, NGCC units, nuclear) with that of non-dispatchable technologies (i.e., g enerating sources that cannot be reliably ramped up or down t o 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 Ta ble 8 below.

As mentioned earlier and discussed in further detai l below, these estimates rely most heavily on DOE/NETL cost projections for fossil fuel generating technologies and on the updated EIA AEO 2015 for non-fossil generation technologies. Re cent***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 272 of 786

estimates from Lazard 273,274 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 275

New Generation Emission LCOE* Technology lb CO 2 /MWh-g $/MWh SCPC - no CCS (bit) 1,620 76 - 95 SCPC – no CCS (low rank) 1,740 75 - 94 SCPC + ~16% partial CCS (bit) 1,400 92 - 117 SCPC + ~23% partial CCS (low rank) 1,400 95 - 121

Nuclear (EIA) 0 87 - 115 Nuclear (Lazard) 0 92 - 132

273 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. 274 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

. 275 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 273 of 786

Biomass (EIA) 276 - 94 – 113 Biomass (Lazard) - 87 - 116 IGCC 1,430 94 - 120 NGCC 1,000 52 – 86** * 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 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. 277 ** This range represents a natural gas price from $ 5/MMBtu to $10/MMBtu. As shown in Table 8, we project that the LCOE for n ew fossil steam capacity meeting the final 1,400 lb CO 2 /MWh-g standard to be substantially similar to that for a new nuclear unit, the principal other alternative to natural ga s to provide

276 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. 277 “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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 274 of 786 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 dispatchabl e base load generation diversity – or at least non-NGCC alterna tives - to a power provider’s portfolio; hence, they are reasona bly viewed as comparable alternatives. 278 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). 279 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

278 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. 279 “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 275 of 786 “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 natural gas because of its competitive current and projected price. However, as noted in Section V.H.3, public I RPs 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. 280 Utilities may be willing to pay a

280 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 276 of 786 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 – dis patchable base load power and fuel diversity.

We further note a number of conservative elements o f the costs we used in making this comparison. In particu lar, these estimates include the highest value in the projecte d range of potential costs for partial CCS. They do not reflec t revenues which can be generated by selling captured CO 2 for enhanced oil recovery, and reflect the costs of partial CCS rath er than potentially less expensive alternative compliance p aths such as a utility boiler co-firing with natural gas. See al so V.H.7 and

8 below.

6. Overall costsCosts and economic impactsEconomic 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 RIA. The RIA demons trates that

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 277 of 786 these costs would be negligible and that the effect s on electricity rates 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 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. 281 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 in the near future. 282 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) – each will deploy IGCC with some

level of CCS. The primary reasons for this rate of current and

281 RIA chapter 4. For example, even in the EIA’s sens itivity 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

. 282 Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 2015.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 278 of 786 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. 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. 283 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 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

283 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 279 of 786 ultimately bear these costs, both directly in the f orm of residential utility bills, and indirectly in the fo rm of higher 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. 284 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. At the same time, total projected

284 Sierra Club , 657 F. 2d at 314.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 280 of 786 costs are relevant in assessing the overall reasona bleness of costs associated with a standard. Our analysis demo nstrates that the impacts on the industry as a whole are negligib le, and are certainly not greater than “what the industry could bear and

survive.” 285 These facts support the EPA’s overall conclusion

that the costs of the standard 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

285 Portland Cement Ass’n , 513 F. 2d at 508.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 281 of 786 costs) as the sole or primary decision tool when re quired to

consider costs or to determine whether to issue regulations under the Clean Air Act, and is not doing so here. 286 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 costsFurther 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 can meet the final standard of p erformance by co-firing with natural gas. Some project developers may choose to utilize natural gas co-firing as a means of dela ying, rather than avoiding, implementation of partial CCS. Devel opers can also choose to install IGCC with a small amount of natural gas

286 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 282 of 786 co-firing at costs within the range of SCPC with pa rtial CCS, although slightly higher. 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. 287 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

287 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 283 of 786 utilization, ranging from exploration to control in stallation. This is true for fossil fuel-fired, as well as nucl ear-, 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-g is the BSER for newly constructed fossil fuel-fired st eam 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-g a new supercritical PC or supercritical CFB can meet the standard by co-firing with natural gas at levels up to appro ximately 40***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 284 of 786 percent (heat input basis) and could potentially av oid (or delay) installation and use of partial CCS altogeth er. 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. EPRI sponsored a study to assess both

technical and economic issues associated with natur al gas cofiring in coal-fired boilers. 288 They determined that the largest number of applications and the longest experience t ime is with natural gas reburning and with supplemental gas fir ing. 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 fuelrich zone where NO 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

288 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 285 of 786 zone. Others have also evaluated configurations tha t would allow coal-fired units to utilize natural gas. 289,290 A 2013 article entitled “Utility Options for Levera ging

Natural Gas” 291 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.

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.

289 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. 290 “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. 291 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 286 of 786

Table 9. Predicted Costs to Meet the Final Standard Using Natural Gas Co-firing. 292 New Generation Emission LCOE Technology lb CO 2 /MWh-g $/MWh SCPC - no CCS 1,620 82 SCPC + ~16% partial CCS 1,400 99 SCPC + ~34% NG co-fire 1,400 92

IGCC - no CCS 1,434 103 IGCC + ~6% NG co-fire 1,400 105 NGCC* 1,000 60 * The generation cost using NG co-fire and NGCC ass ume a natural gas price of $6.19/mmBtu.

The EPA thus again notes that the cost assumptions it is making in its BSER determination are conservative. That is, by costing partial CCS as BSER, the EPA may be overest imating actual compliance costs since there exist other les s expensive means of meeting the promulgated standard. 293 Notwithstanding that costs for a SCPC to meet the s tandard would be lower if it co-fired with natural gas, we have not

292 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. 293 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 287 of 786 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, 294 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 performance, and is available at reasonable cost an d (as shown at Section V.P below) without significant adverse nonairnon-air quality impacts or energy implications. b. Costs are reasonably expected to decrease over t ime

. 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

294 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 288 of 786 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 at least 30 percent less than that at Unit #3. 295 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. 296 This consortium

295 “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). 296 http://www.saskpowerccs.com/consortium //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 289 of 786 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). 297 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 facilities to test new capture technologies for ext ended periods under commercially representative conditions with c oal-derived flue gas and syngas. 298 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

297 www.saskpowerccs.com/ccs-projects/shand-carbon-cap ture-testfacility //. 298 www.nationalcarboncapturecenter.com/index.html

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 290 of 786 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 ca ptured 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 291 of 786 intend to use captured CO 2 to improve recovery of oil in mature

fields. 299 See also Section V.M. 23 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.

1. Use of LCOE as a cost metricCost Metric As noted, CAA section 111(a) directs the EPA to con sider “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

299 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 292 of 786 emission reduction, but rather measures the impact on the product produced by the entity subject to the stand ard. 300 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 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, LCOE 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 costs per unit of production (i.e., megawatt-hours) . Provided that those megawatt-hours provide similar electrici ty services and align on dimensions other than just cost, then the LCOE

300 Comments of EEI, pp 94-5.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 293 of 786 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 as discussed in Section V.H.4 above, the EPA accordingly has consid ered direct capital costs here as part of its assessment and fo und those costs to be reasonable. In addition, the EPA notes that its comparison of the marginal impacts from an individu al illustrative facility’s compliance with the standar d, discussed in detail above and in the RIA Chapter 5, took into account the marginal capital costs that would be incurred by an individual facility. At the same time, the agency believes LCOE is a val uable complementary metric because there

are other costs that are also considered when evalu ating technology options to provide new generating capacity. According to EIA 301 , the capital costs represent roughly approximately 63 percent of the LCOE for a new coal-fired SCPC plant; roughly approximately 66 percent of the LCOE for a new IGCC plant; roughly approximately 74 percent of the LCOE for a new nuclear plant; and only about 22 percent of the LCO E 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

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

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 294 of 786 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 consider ed, 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 beyond capital cos ts , and

. Accordingly, in considering cost reasonableness we accordingly also the

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 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 filin gs in the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 295 of 786

docket 302 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 o f their LCOE is a valid approach to evaluating cost reasonablene ss. 2. Use of cost estimatesCost 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 AEO 2013 projections for no n-fossil based generating sources (i.e., nuclear, renewables , etc.). For this final rule, the EPA continues to rely most hea vily on DOE/NETL cost projections for fossil fuel generatin g technologies and on the updated DOE/EIA AEO 2014 fo r nuclear and other base 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

302 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 296 of 786 and storage. 303 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 for producing high quality, reliable work. 304 The NETL studies were extensively peer reviewed. 305 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 by agency guidance.” 306

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

. 304 The NETL costs and studies are often cited in acad emic and other publications. 305 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. 306 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 297 of 786 The cost estimates were indicated by DOE/NETL to ca rry an accuracy of -15 percent to +30 percent on the capit al costs,

consistent with a AACE Class 4 cost estimate – i.e. , a “feasibility study” level of design engineering. 307 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.” 308 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. 309 The EPA used this latest version of the NETL studi es

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. 307 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. 308 “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. 309 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 298 of 786 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 estimat es . A variety of government, industry and academic grou ps routinely conduct studies to estimate costs of new generating 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) 310 , by the DOE’s Energy Information Administration (EIA) in their 2015 Annu al Energy Outlook (AEO 2015), by the DOE’s National Energy Te chnology Laboratory (NETL), and by researchers from the Depa rtment of Engineering and Public Policy at the Carnegie Mello n University (CMU) in Pittsburgh, PA.

310 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 *** Page 299 of 786

The Global CCS Institute 311 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.

311 www.globalccsinstitute.com

.*** EO 12866 Review - Draft – Do Not Cite, Quote orRelease During Review ***Table 10. Selection of Levelized Cost of Electricity (LCOE) ProjectionsNew GenerationLazard312EPRI313AEO2015314DOE/NETL315CMU316GCCSI317**Technology$2014/MWh$2011/MWh$2013/MWh*$2011/MWh*$2010/MWh$2014/MWhSCPC – no CCS 66 62 – 77 95 76 – 95 59 78SCPC - full CCS 151 102 – 137 - 140 – 176 - 115 - 160SCPC - 16% CCS - - - 92 - 117 - -Nuclear*** 92 – 132 85 – 97 87 – 115 - - 86 - 102Biomass 87 – 116 90 – 155 94 – 113 - - 123 - 137IGCC 102 82 – 96 116 94 – 120 - -IGCC - full CCS 171 105 – 136 144 142 – 178 - -NGCC 61-–8733 – 65 73 58 63 60* EIA, in cost projections for SCPC and IGCC with no CCS, includes a climate uncertaintyadder (CUA), which is a 3-percentage point increasein the cost of capital. In contrast,312Lazard’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.313"Program on Technology Innovation: Integrated Generation Technology Options 2012;Report 1026656; Available at:www.epri.com.314“Levelized Cost and Levelized Avoided Cost of NewGeneration Resources in the AnnualEnergy Outlook 2015”, Available at: www.eia.gov/forecasts/aeo/electricity_generation.cfm;the LCOE values displayed incorporate -10%/+30% foruncertainty for biomass and nuclear.315“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).316CMU 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 1.317“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.***EO 12866_Review - Draft – Do Not Cite, Quote orRelease During Review ***Page301of786DOE/NETL utilized conventional financing for caseswithout CCS and utilized high-riskfinancial assumptions for cases that include CCS.** 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, and NETL stu dies are presented as a range. The EPRI costs incorporate un certainty reflecting the range of inputs (i.e., capital costs , fuel costs, fixed and variable O&M, etc.). The NETL costs are i ndicated to carry an accuracy of -15 percent to + 30 percent, c onsistent with a “feasibility study” level of design. The ran ge in Table 10 is the NETL projected costs with the -15 percent to +30 percent uncertainty on the capital costs. Overall, as can be seen from the results in Table 10, the range of LCO E estimates from the different groups are in reasonable agreeme nt 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 (demonstrable through IRPs and PUC orders) and is t herefore pertinent when evaluating the cost competitiveness of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 303 of 786 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. c. Industry information that corroborates NETL cost estimates

. Information from vendors of CCS technology also sup ports the reliability of the cost estimates the EPA is using here. 318 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. 319 Summit is actively working with several different technology companies offering CO 2 capture 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

318 See Section V.F above, explaining that the D.C. Ci rcuit has repeatedly stated that vendor statements are probat ive in demonstrating that a technology is adequately demon strated under section 111. 319 http://www.summitpower.com/projects/carbon-capture //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 304 of 786 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. 320 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. 321 Though the primary focus of their effort was to 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

320 “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. 321 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 During Review *** Page 305 of 786 with costs predicted by NETL, EIA, EPRI and others. The company ultimately concluded that “in a world of uncertain gas prices, falling CO 2 capture equipment prices, improving CCS process efficiency, and possible compliance costs ... existin g coal plants retrofitted with available CCS equipment can be cos t competitive with development of new NGCC generation.” 322 In June 2012, Alstom Power released a report entitl ed “Cost assessment of fossil power plants equipped with CCS under typical scenarios”. 323, 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 American case – along with similar cost estimates f rom Summit – are shown in Table 11 below. The DOE/NETL estimated costs are also included for comparison. The results show pred icted costs for a new SCPC ranging from $53/MWh to $82/MWh and costs to implement full CCS ranging from $97/MWh to $143/MWh . Costs to

322 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). 323 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 During Review *** Page 306 of 786 implement varying levels of partial CCS are also pr ovided for comparison. The industry cost estimates are on the lower end of the range of costs predicted from other techno-econ omic studies (see Table 11 below) and, like those economic studi es, are affected by the specific assumptions. As with the t echo-economic studies presented earlier in Table, there is relati vely good agreement among these projected costs and the DOE/N ETL costs. There is relatively good agreement in the increment al levelized cost to implement full CCS on the new SCPC units (r anging from 74 to 85 percent) and to implement 50 percent CCS o n the new SCPC unit (from 41 to 45 percent increase). These i ndustry estimates are also lower than the DOE/NETL estimate s for both full and 50 percent partial CCS (with the increment al cost percentage for full CCS being almost identical), pr oviding further support for the reasonableness of the EPA u sing the NETL

cost estimates here. Table 11. Industry LCOE Estimates for Implementatio n of PostCombustion CCS 324 Summit Alstom DOE/NETL

324 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 307 of 786

$/MWh $/MWh* $/MWh SCPC 64.5 52.6 82.3 SCPC + full CCS 117.6 97.4 152.4 Full CCS incremental cost, % 82.3% 85.0% 85.2% SCPC + 50% CCS 91.1 - 123.6 50% CCS incremental cost, % 41.2% - 50.1% SCPC + 35% CCS - - 114.7 SCPC + 16% CCS - - 100.5 NGCC** 47.7 35.0 52.0** * 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 information. Assumed natural gas prices = Summit ($4/mmBtu); Ast om ($3.9/mmBtu); EPA ($5.00/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.” 325 As explained above, no steam electric EGU would be cost competit ive even without CCS – and that is substantiated in the proj ected costs presented above in Table 11 where NGCC is consisten tly the most economic new generation option when compared to the other listed technologies. Alstom does not explain (or address) why the cost premium for partial CCS would be a decisive deterre nt for capacity that would otherwise be constructed. More important,

325 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 During Review *** Page 308 of 786 Alstom does not challenge the specific cost estimat es used by the EPA at proposal, nor disavow its own estimates of CCS costs (which are even less) which it is publically dissem inating in the marketplace. See also Section V.F. 3 above, quo ting Alstom’s press release stating unequivocally that “CCS works and is costeffective”. The EPA reasonably is relying on the sp ecific Alstom estimates which it is using for its own commercial purposes, and not on the generalized concerns presented in its pu blic

comments. d. Use of cost information from EIA Annual Energy O utlook (AEO ). ) For the January 2014 proposal the EPA chose to rely on the EIA AEO 2013 cost projections for non-fossil based generation. The AEO presents long-term annual projections of en ergy supply, demand, and prices focused on U.S. energy markets. The predictions are based on results from EIA’s Nationa l Energy Modeling System (NEMS). The AEO costs are updated a nnually, 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 AEO 2013. Those costs were update d as part of

the AEO 2015 release. The estimated cost for all of these technologies decreased from AEO 2013 to AEO 2014 an d AEO 2015.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 309 of 786 This was due to changes in the interest rates that resulted in lower financing costs relative to those used the AE O 2013. 326 The EIA commissioned a comprehensive update of its capi tal cost assumptions for all generation technologies in 2013 . Fuel cost and financial assumptions are updated for each edit ion of the Annual Energy Outlook. 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. The DOE/NETL noted that the cost estimates from the ir studies carry an accuracy in the range of -15 perce nt to +30

326 www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantc osts.pdf.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 310 of 786 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 AEO 2015 presented LCOE costs as a single p oint estimate representing average nationwide costs and separately as a range to represent the regional variation in cost s. In order to compare the fossil fuel generation technologies from the NETL studies with the cost projections for non-fossil di spatchable technologies from EIA AEO 2015, we assume that the EIA studies would carry a similar level of uncertainty (i.e., + 30 percent) and we present the AEO 2015 projected costs as the average nationwide LCOE with a range of -10 percent to +30 percent to account for uncertainty. 327 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

327 EIA does not provided uncertainty estimates in the AEO cost projections. However, EIA staff have indicated to the 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. [expand and docket email and cite to it].See memorandum “Ra nge of uncertainty for AEO nuclear costs” available in the rulemaking docket, EPA-HQ-OAR-2013-0495.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 311 of 786 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 Institute, in its most recent cost update, also pro vides nuclear costs as a range from $86/MWh to $102/MWh. 328

3. Use of costsCosts from current projectsCurrent 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

328 “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

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 312 of 786 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. 329 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

329 The EPA notes that two of these facilities, Kemper and TCEP, received both assistance from DOE under EPAct05 and the IRC section 48A tax credit; and that the AEP Mountainee r pilot project received assistance from DOE under EPAct05. Under the most extreme interpretations of those provisions of fered 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. 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 313 of 786 solvents and is currently being constructed with pl ans to initiate operation in 2016. 330 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. 331 Another full-scale project, the Summit Power Texas Clean Energy Project has not commenced construction but r emains a viable project. Several other full-scale projects h ave been proposed and have progressed through the early stag es 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.

330 http://www.nrg.com/sustainability/strategy/enhance

generation/carbon-capture/wa-parish-ccs-project //. 331 http://www.mississippipower.com/about-energy/plant s/kempercounty-energy-facility/facts

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 314 of 786 Many commenters felt that the EPA should rely on th ose high costs when considering whether the costs are reason able. 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 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 case s, the report intends to represent the next commercial offering, and relies on vendor cost estimates for component technologies. I t also***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 315 of 786 applies process contingencies at the appropriate su bsystem levels in an attempt to account for expected but un defined costs (a challenge for emerging technologies).” 332 Commenters argued that the next plants to be built would still reflect first-of-a-kind costs, pointing to th e newness of the technology and the lack of operating experience , i.e. the alleged absence of learning by doing. The EPA disag rees. In addition to operating experience from operating and partially constructed CCS projects, substantial research effo rts are underway providing a further knowledge base to redu ce CO 2 capture costs and to improve performance. The DOE/NETL sponsors an extensive research, develo pment and demonstration program that is focused on develo ping advanced technology options that will dramatically lower the cost of capturing CO 2 from fossil fuel energy plants compared to currently available capture technologies. The large -scale CO 2 capture demonstrations that are currently planned a nd in some cases underway, under DOE’s initiatives, as well as other domestic and international projects, will generate operational knowledge and enable continued commercialization an d deployment of these technologies. Gas absorption processes usi ng chemical

332 “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 During Review *** Page 316 of 786 solvents, such as amines, to separate CO 2 from other gases have been in use since the 1930s in the natural gas indu stry and to produce food and chemical grade CO 2 . The advancement of aminebased solvents is an example of technology developm ent that has improved the cost and performance of CO 2 capture. Most single component amine systems are not practical in a flue gas environment as the amine will rapidly degrade in th e presence of oxygen and other contaminants. The Fluor Econamine FG process, the process modeled in the NETL cost study for the SCPC cases, uses a monoethanolamine (MEA) formulation specially designed to

recover CO 2 and contains a corrosion inhibitor that allows the use of less expensive, conventional materials of co nstruction. Other commercially available processes use sterical ly hindered amine formulations (for example, the Mitsubishi Hea vy Industries KS–1 solvent) which are less susceptible to degrada tion and

corrosion issues. 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. As noted in Section V.H.7.d above, SaskPower has cr eated

the CCS Global Consortium to facilitate further kno wledge regarding, and use of, carbon capture technology. 333 This

333 http://www.saskpowerccs.com/consortium //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 317 of 786 consortium provides SaskPower the opportunity to sh are its knowledge and experience with global energy leaders , technology developers, and project developers. SaskPower, in p artnership with Mitsubishi and Hitachi, is also helping to adv ance CCS knowledge and technology through the creation of th e Shand Carbon Capture Test Facility (CCTF). 334 The test facility will provide technology developers with an opportunity t o 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 suggest that their costs are uni quely high, and otherwise not fairly comparable to the costs of plants meeting the NSPS using the BSER. Most obviously, ma ny of these projects involve deeper capture than the partial CC S that the EPA assumes in this final action. In addition, cost overruns at the Kemper facility, mentioned repeatedly in the pu blic comments, resulted in major part from highly idiosy ncratic circumstances, and are related to the cost of the I GCC system,

not to the cost of CCS. 335 The EPA does not believe that these

334 http://www.saskpowerccs.com/ccs-projects/shand-car boncapture-test-facility //. 335 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 318 of 786

unusual circumstances are a reasonable basis for as sessing costs

of either CCS or IGCC here.

4. Cost competitivenessCompetitiveness of new coal unitsNew 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 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

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 During Review *** Page 319 of 786 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. Some commenters, however, disagreed with this concl usion. They contended instead that it is the CCS-based NSP S that would preclude such new generation. However, as the EPA h as discussed, there is considerable evidence that utilities and p roject developers are moving away – or have already moved away – from a long term dependence on coal-fired generating sourc es. A review of publicly available integrated resource plans sho w that many utilities are not considering construction of new c oal-fired

sources without CCS. See Section V. H.3 above. Few new coalfired generating sources have commenced constructio n in the past 5 years and, of the projects that are currently in the development phase, the EPA is only aware of project s that will include CCS in the design. As we have noted in this preamble, the bulk of new generation that has been added rece ntly has been either natural gas-fired or renewable sources. Over all, the EPA remains convinced that the energy sector modeling i s reflecting the realities of the market in predicting very few new coalfired power plants in the near future – even in the absence of

these final standards.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 320 of 786 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”. 336 Indeed, AEP has 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.” 337 Today’sThis

336 www/aep.com/newsroom/newsreleases/?id=1704. 337 “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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 321 of 786

final rule’s action is an important component in developing tha t needed regulatory framework

. 5. Accuracy of cost estimatesCost Estimates for transportationTransportation and geologic sequestrationGeologic Sequestration

The EPA’s estimates of costs 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 consi stent with other published studies. 338 For transport, costs reflect 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

338 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 Captu re (DOE/NETL2011/1498); Cost and Performance Baseline for Fossil Energy Plants (DOE/NETL-2010/1397); Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Valley Auth ority, NETL and EPRI, December 2002 ; Carbon Dioxide and Transport and Storage Costs in NETL Studies (DOE/NETL-2013/1614), March 2013; Carbon Dioxide and Transport and Storage Costs in N ETL Studies (DOE/NETL-2014/1653), May 2014; Cost and Performance Baseline for Fossil Energy Power Plants, Volume 1a: Bitumino us Coal (PC) and Natural Gas to Electricity (DOE-NETL-2015/1723), July 2015.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 322 of 786 the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO 2 in deep saline formations, which are discussed further in Sections V. M. and N

below. 339 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 . 340 The range of TSM costs the EPA relied on are broadly consistent with estimates provided by t he Global Carbon Capture and Storage Institute as well. 341 Some commenters suggested that the EPA underestimated the costs ass ociated with transporting captured CO 2 from an EGU to a sequestration site. 342 Specifically, commenters suggested that the EPA’s e stimated costs for constructing pipelines were lower than co sts based on actual industry experience. Commenters also opined that the EPA’s assumed length of pipeline needed between the EGU and the sequestration site is not reasonable and that the D OE/NETL study

339 Carbon Dioxide and Transport and Storage Costs in NETL Studies. DOE/NETL-2013/1614. March 2013. P. 13. 340 RIA at section 5.5; proposed rule RIA at 5-30. 341 http://hub.globalccsinstitute.com/sites/default/fil es/publicatio ns/12786/economic-assessment-carbon-capture-and-sto ragetechnologies-2011-update.pdf. 342 See, for example, comments from American Electric, pp 97-8, Southern Company, pp. 47-48, and Duke Power p. 98.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 323 of 786 upon which the EPA relied does not account 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

includes cost estimates for CO 2 transport when EOR opportunities

are not available – consistent with its overall con servative cost methodology of assuming no revenues from sale of captured

CO 2 . Specifically, the EPA estimates transport, storag e and monitoring (TSM) costs of $5-$15 per ton of CO 2 for non-EOR applications. 343 This estimate is reflected in the LCOE comparative costs. 344 The EPA also carefully reviewed the assumptions on which the transport cost estimates are based and continue s to find

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. 345 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. 346 As a point of reference, the longest CO 2

343 See RIA at section 5.5 and proposed RIA at 5-30. 344 See RIA at section 5.5. 345 The pipeline diameter was sized for this to be ach ieved without the need for recompression stages along the pipeline length. 346 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gu pta, SH Kim, EL Malone (2006), Carbon Dioxide Capture and G eologic***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 324 of 786 pipeline in the United States is 502 miles. 347 For new sources, pipeline distance and costs can be factored into si ting and, as discussed in Section V.M, there is widespread avail ability of geologic formations for geologic sequestration (GS) . Moreover, data from the Pipeline and Hazardous Materials Safe ty Administration show that in 2013 there were 5,195 m iles of CO 2 pipelines operating in the United States. This repr esents 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

have a reasoned basis. See also Section V.M below f urther 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 GHGRP subpart RR, and also was not representative of the costs associated with specific GS site characterization, development, and operation/injection of monitoring wells. Commen ter American

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. 347 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 During Review *** Page 325 of 786 Electric Power (AEP) referred to its own experience with the Mountaineer demonstration project. AEP noted that a lthough this project was not full scale, finding a suitable repo sitory, notwithstanding a generally favorable geologic area , proved difficult. The company referred to its estimated co st of expanding the existing Mountaineer plant to a large r scale project, particularly the cost of site characteriza tion and well

construction. 348 The EPA’s cost estimates account for the requiremen ts of the Underground Injection Control Class VI program, and GHGRP subpart RR, among them site screening and evaluatio n costs, costs for injection wells and equipment, O&M costs, and monitoring costs. The estimated sequestration costs include operational and post-injection site care monitoring , which are components of the UIC Class VI requirements, and al so reflect costs for sub-surface pore volume property rights a cquisition. 349 These estimates are consistent with the costs prese nted in the study CO 2 Storage and Sink Enhancements: Developing Comparab le

348 AEP Comments at pp. 93, 96. 349 “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture.” DOE/NETL-2011/1498 (Septem ber 2013) p. 49. Specifically, the report estimates the costs as sociated with acquiring rights to use the pore space in the geolo gic formation. Costs are estimated based on studies of subsurface rights acquisition for natural gas storage. The rep ort also estimates costs for land acquisition for surface pr operty rights. Id. p. 48.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 326 of 786

Economics , which incorporates the costs associated with site evaluation, well drilling, and the capital equipmen t required for transporting and injecting CO 2 . 350,351 Monitoring costs were evaluated based on the methodology set forth in the International Energy Agency Greenhouse Gas R&D Prog ramme’s Overview of Monitoring Projects for Geologic Storag e Projects report. 352 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. 353 That analysis

350 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. 351 As noted above, other sequestration-related costs are also estimated, including injection wells and equipment, pore volume acquisition, and long-term-liability. “Cost and Per formance Baseline for Fossil Energy Plants Volume 1: Bitumin ous Coal and Natural Gas to Electricity Revision 2a, Septemb er 2013 DOE/NETL-2010/1397, p. 55. 352 “Overview of Monitoring Requirements for Geologic Storage Projects”, IEA Greenhouse Gas R&D Programme, Report Number PH4/29, November 2004. 353 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 327 of 786 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 assumption s regarding the assumed injection site: a deep saline formation with typical characteristics (e.g., representative depth and pre ssure). 354 With respect to AEP’s experience with the Mountaine er demonstration project, sequestration siting issues are of course site-specific, and raise individual issues. For thi s reason, it is inappropriate to generalize from a particular in dividual experience. In this regard, as explained in Section V.N 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 . The company also indicated it fully expected to b e able to do so at full scale and explained how. 355 For discussion

354 Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002. 355 See “CCS front end engineering & design report: Am erican Electric Power Mountaineer CCS II Project. Phase 1” at pp. 36- 43. The company likewise explained the monitoring r egime it would utilize to verify containment, and the well c onstruction***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 328 of 786 of 40 CFR part 98 subpart RR (the GHGRP requirement s for geologic sequestration), including costs associated with compliance with those requirements, see Section V.N below. J. Achievability of the Final Standards 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 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. 356 This is in

it would utilize to guarantee 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

. 356 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 During Review *** Page 329 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 330 of 786 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 plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent. 357 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

357 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”).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 331 of 786 uncontrolled emission rate about 7 percent higher t han a similar unit firing typical bituminous coal. 358 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

evaluated those costs and finds them to remain reas onable. 359 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. 360 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.

358 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. 359 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

. 360 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 During Review *** Page 332 of 786 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 at 326 (“we can think of no sensible interpretation o f the statutory words “best ... system” which would not inc orporate the amount of air pollution as a relevant factor to be weighed when determining the optimal standard for controlling ... emissions”). 361 This is consistent with the Court’s statements in Essex Chemical Corp. v. Ruckelshaus , 486 F.2d at 437 that it is necessary to “[k]eep [ ][] in mind Congress’ intent that new plants be controlled to the ‘maximum practicable de gree’”. 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

361 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 .”***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 333 of 786 highly efficient 500 MW coal-fired SCPC meeting the final standard of 1,400 lb CO 2 /MWh-g will emit about 354,000 fewer

metric tons of CO 2 each year than that new highly efficient unit would have emitted otherwise. That is equivalent to taking about 75,000 vehicles off the road each year 362 and will result in over 14,000,000 fewer metric tons of CO 2 in a 40-year operating life. To emphasize the importance of constructing a highl y efficient SCPC unit that includes partial CCS - the highly ef ficient 500 MW coal-fired SCPC with partial CCS would emit abou t 675,000

fewer metric tons of CO 2 each year than that from a new, less efficient coal-fired utility boiler with an assumed emission of 1,800 lb CO 2 /MWh-g. For comparison, see Table 12 below which provides t he

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 60,000,00 0 metric tons

of CO 2 were supplied to U.S. EOR operations in 2013. 363

Table 12. 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

362 Using U.S. EPA Office of Transportation and Air Qu ality (OTAQ) estimate of average vehicle emissions of 4.7 tonnes/year. 363 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 334 of 786 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 EGU (1,400 lb CO 2 /MWh-g) 354,000 Coffeyville Fertilizer 700,000 Boundary Dam #3 1,000,000 Petra Nova/NRG WA Parish 1,400,000 Dakota Gasification 3,000,000

L. Further Development and Deployment of CCS Techno logy Researchers at Carnegie Mellon University (CMU) hav e studied the history and the technological response to environmental regulations. 364 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

364 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 During Review *** Page 335 of 786 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. Many of the early Flue Gas Desulfurization (FGD) un its did not perform well, as the technology at that time wa s poorly understood and there was little or no prior experie nce on coalfired power plants. In contrast, amine-based captur e systems have a much longer history of reliable use at coal- fired plants

and other industrial sources. There is also a bette r 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 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 exis tence 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 336 of 786 author further found that regulatory stringency app ears to be 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. M. Technical and Geographic Aspects 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. In this section, we review the existing processes, technologies, and geologic conditions th at enable successful geologic sequestration (GS). In Section V.N., we discuss in detail the comprehensive, in-place regul atory structure that is currently available to oversee GS projects and assure their safety and effectiveness. Together, th ese discussions demonstrate that the technical feasibil ity of GS, another key component of a partial CCS unit, is ade quately***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 337 of 786 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 GHGRP, together ensure that sequestered CO 2 will remain secure and provide the monitoring to identify and address potential leakag e using Safe Drinking Water Act (SDWA) and CAA authorities (see Section V.N of this preamble). 365 1. Geologic and Geographic Considerations for GS Geologic sequestration (i.e., long-term containment of a CO 2 stream in subsurface geologic formations) is techni cally 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

365 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 During Review *** Page 338 of 786 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 trapping (adsorption onto organic matter in coal an d shale). 366 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. 367 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. 368 In addition, site characterization, site

366 See, e.g., USEPA. 2008. Vulnerability Evaluation F ramework for Geologic Sequestration of Carbon Dioxide. 367 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 47. 368 See, e.g., Intergovernmental Panel on Climate Chan ge. (2005). Special Report on Carbon Dioxide Capture and Storag e.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 339 of 786 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. 369 For example, CO 2 has been trapped for more than 65 million years in the Jackson Dome, located near Jackson, Mississippi

. 370 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. 371 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

369 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. 370 Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage. 371 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 340 of 786 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. 372 As shown in the figure, there are 39 states for which onshore and o ffshore deep saline formation storage capacity has been identifi ed. 373 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 with in 100 kilometers (62 miles) of where storage capacity has been

identified. 374 There are 10 states with operating CO 2 pipelines and 18 states that are within 100 kilometers (62 mi les) 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

372 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. 373 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. 374 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 341 of 786 storage. 375 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 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. 376 The availability of unmineable coal seams is shown in F igure 1

below. As discussed below in Section M.7, a few states do not have geologic conditions suitable for GS, or may not be located in proximity to these areas. However, in some cases, d emand in those states can be served by coal-fired power plan ts located in areas suitable for GS, and in other cases, coal-fir ed power plants are unlikely to be built in those areas for other

375 Other types of opportunities include organic shale s and basalt. 376 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 During Review *** Page 342 of 786 reasons, such as the lack of available coal or stat e law prohibitions and restrictions against coal-fired po wer plants. 377

377 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 c oal plants as it intends to utilize 100 percent renewable energy sources by 2050.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 343 of 786

Figure 1: Geologic Sequestration in the Continental United

States***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 344 of 786***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 345 of 786 Figure 2 – Electrical Transmission Lines across the

Continental United States 378

2. Availability of Geologic Sequestration in Deep S aline

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

. 379 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

378 Ventyx Velocity Suite Online. April 2015. 379 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 During Review *** Page 346 of 786

assessment. 380 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. 381 The seven partnerships include more than 400 organizations spanning 43 states (and four Canadian provinces). 382 RCSP project objectives are to inject at least one

million metric tons of CO 2 . In April 2015, DOE announced that CCS

380 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/. 381 http://energy.gov/fe/science-innovation/carbon-cap ture-andstorage-research/regional-partnerships. 382 http://energy.gov/fe/science-innovation/carbon-cap ture-andstorage-research/regional-partnerships.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 347 of 786 projects supported by the department have safely an d permanently

stored 10 million metric tons of CO 2 . 383 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. 384 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. 385 No CO 2 leakage has been reported from these sites, which further supports the availability of effectiv e GS.

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

. 384 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. 385 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 During Review *** Page 348 of 786 3. 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 During Review *** Page 349 of 786

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 During Review *** Page 350 of 786 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. 386 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 N below) that can be used for deployme nt 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 18 states are within 100 kilometers ( 62 miles) of current EOR operations. See Figure 1 above. The vas t majority of

EOR is conducted in oil reservoirs in the Permian B asin, which extends through southwest Texas and southeast New M exico. States

386 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 During Review *** Page 351 of 786 where EOR is utilized include Alabama, Colorado, Lo uisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. Several commenters raised concerns about t he 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 EGU s. 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 oi l field may last for decades, injecting into multiple parts of the field. 387 According to data reported to the EPA’s GHGRP, appr oximately 60

million metric tons of CO 2 were supplied to EOR in the United

States in 2013. 388 Approximately 70 percent of this total CO 2 supplied was produced from natural (geologic) CO 2 sources and approximately 30 percent was captured from anthropo genic

sources. 389

387 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. 388 Greenhouse Gas Reporting Program, data reported as of August 18, 2014. 389 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 352 of 786 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. 390 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. 391 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

390 “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. 391 “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 During Review *** Page 353 of 786 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 . 392 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

392 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 During Review *** Page 354 of 786 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. 393 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. 394 The International Energy Agency Greenhouse Gas Prog ramme

393 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. 394 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 During Review *** Page 355 of 786 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. 395 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 L.1 above). 396 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. 397 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 M.1 above and as shown in F igure 1, the United States has widespread potential for stor age, including in deep saline formations and oil and gas formations.

395 Hitchon, B. (Editor), 2012, Best Practices for Val idating CO 2 Geological Storage: Geoscience Publishing, p. 353. 396 http://www.beg.utexas.edu/gccc/cranfield.php. 397 http://www.beg.utexas.edu/gccc/cranfield.php.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 356 of 786 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. 398 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. 399 Other commenters noted significant geographic disparity i n GS site availability, claiming absence of sites in southeas tern areas of the country. 400 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 M.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 a lternative means of complying with the final standards of perf ormance that

398 Comments of Southern Co., p. 38. 399 Comments of AEP pp. 93, 96. 400 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 During Review *** Page 357 of 786 do not necessitate use of partial CCS, so any sitin g 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. 4. 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. Th ese carbonate

materials have been used in the construction indust ry and, more***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 358 of 786 recently and innovatively, in cement production pro cesses to replace Portland cement. The Skyonics Skymine project, which opened its demonstration project in October 2014, is an exampl e 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 an d bleach. 401 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 technologies not only show promise, but could poten tially be demonstrated to show permanent storage of CO 2 .

401 http://skyonic.com/technologies/skymine.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 359 of 786 In the January 2014 proposal, the EPA noted that it 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 360 of 786 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 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 . 402 CO 2 has been transported via pipelines in the United States for nearly 40 years. Over this time, the design, construction, op eration, 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. 403

402 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 36. 403 “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 During Review *** Page 361 of 786 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 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. 404

404 “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 During Review *** Page 362 of 786 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 pipelines in the Gulf Coast region. 405 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. 406 Denbury completed the final section of the 325-mile Green Pipeline for transporting CO 2 from Donaldsonville, Louisiana, to

EOR oil fields in Texas. 407 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. 408 A project being constructed by NRG and JX Nippon Oi l & Gas Exploration (Petra Nova) would capture CO 2 from a power plant in

405 “2013 Annual Report”, Denbury, April 2014. Availab le at http://www.denbury.com/files/doc_financials/2013/De nbury_Final_0 40814.pdf. 406 “CO 2 Sources”, Denbury, 2015. Available at: http://www.denbury.com/operations/rocky-mountain-re gion/co2- sources-and-pipelines/default.aspx. 407 http://www.denbury.com/operations/gulf-coastregion/Pipelines/default.aspx. 408 “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 During Review *** Page 363 of 786 Fort Bend County, Texas for transport to EOR sites in Jackson County, Texas through an 82-mile CO 2 pipeline. 409 The project is anticipated to commence operation in 2016. 410 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, 354 (J an. 3, 2014). Existing and new CO 2 pipelines are comprehensively regulated by the Department of Transportation’s Pipeline Hazardo us Material Safety Administration. The regulations govern pipel ine design, construction, operation and maintenance, and emerge ncy response planning. See generally 49 CFR 195.2. Additional re gulations address pipeline integrity management by requiring heightened scrutiny to assure the quality of pipeline integrit y in areas

409 “The West Ranch CO 2 -EOR Project, NRG Fact Sheet”, NRG, 2014. Available at: www.nrg.com/documents/business/pla-2014-westranch-fact-sheet.pdf. 410 “WA Parish Carbon Capture Project”, NRG, 2015. Ava ilable at: www.nrg.com/sustainability/strategy/enhance-generat ion/carboncapture/wa-parish-ccs-project/.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 364 of 786 with a higher potential for adverse consequences. S ee 49 CFR 195.450 and 195.452. On-site pipelines are not subj ect to the Department of Transportation standards, but rather adhere to the Pressure Piping standards of the American Society o f Mechanical Engineers (ASME B31), which the EPA has found would ensure that piping and associated equipment meet certain qualit y and safety criteria sufficient to prevent releases of CO 2 , such that certain additional requirements were not necessary (See 79 FR 358-59 (Jan. 3, 2014)). 411 These existing controls over CO 2 pipelines assure protective management, guard against release s, and assure that captured CO 2 will be securely conveyed to a sequestration

site. 6. States with Emission Standards That Would Requir e 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 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

411 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 During Review *** Page 365 of 786 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.

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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 366 of 786 In May 2007, Montana Governor Schweitzer signed Hou se Bill 25, adopting a CO 2 emissions performance standard for EGUs in the state. House Bill 25 prohibits the state Public Uti lity Commission from approving new EGUs 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. 7. Coal-by-wire In addition, as discussed in the proposal, electric ity demand in states that may not have geologic sequest ration sites may be served by coal-fired electricity generation built in nearby areas with geologic sequestration, and this electricity can be delivered through transmission lines. This m ethod, known as “coal-by-wire,” has long been used in the electr icity 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 367 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 368 of 786 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. 412 A review of Figure 1 indicates limited areas that do not fall i nto these categories. 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. 413 As one considers the areas on the map depicted in F igure 1 that fall outside of the above enumerated categorie s, in many

412 The NETL cost estimates for CO 2 transport assume a pipeline of 100 kilometers. NETL (2015) at p. 44. 413 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 During Review *** Page 369 of 786 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 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 414 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 C O 2 This section discusses the different regulatory com ponents, already in place, that assure the safety and effect iveness of

414 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 During Review *** Page 370 of 786 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. In 2010, the EPA finalized an effective and coheren t regulatory framework to ensure the long-term, secur e and safe storage of large volumes of CO 2 . The EPA developed these Underground Injection Control (UIC) Class VI well r egulations under authority of the Safe Drinking Water Act (SDW A) to facilitate injection of CO 2 for GS, while protecting human health and the environment by ensuring the protection of u nderground sources of drinking water (USDWs). The Class VI reg ulations are built upon 35 years of federal experience regulatin g underground injection wells, and many additional years of state UIC program expertise. The EPA and states have decades of UIC e xperience with the Class II program, which provides a regulat ory framework for 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 G HGRP. Information collected under the GHGRP provides a tr ansparent***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 371 of 786 means for the EPA and the public to continue to eva luate the

effectiveness of GS. As explained below, these requirements help ensure that sequestered CO 2 will remain in place, and, using SDWA and CAA authorities, provide the monitoring mechanisms to i dentify and address potential leakage. We note the near consens us in the public responses to the Class VI rulemaking that sa line and oil and gas reservoirs provide ready means for secure G S of CO 2 . 415 1. Requirements for UIC Class VI and Class II Wells 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 standard s 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

415 “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 During Review *** Page 372 of 786 saline formations, but also can apply to injection into

unmineable coal seams and other formations. See 75 FR 77256 (Dec. 10, 2010). 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. 416 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

416 40 CFR §144.3.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 373 of 786 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 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. 417 Notably: Site characterization includes assessment of the ge ologic, hydrogeologic, geochemical, and geomechanical prope rties of a

417 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 developed 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 During Review *** Page 374 of 786 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 faults or fractures to ensure USDW protection. 418,419 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. 420 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. 421 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. 422 Within the area of review, owners or operators must identify and evaluate all artificial penetrations

418 75 FR 77240 and 75 FR 77247 (December 10, 2010). 419 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.) 420 40 CFR §146.81(d). 421 40 CFR §146.95. 422 40 CFR §146.84(a).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 375 of 786 to identify those that need corrective action to pr event the

movement of CO 2 or other fluids into or between USDWs. 423,424 Due 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. 425 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. 426

Well construction must use materials that can withs tand

contact with CO 2 over the operational and post-injection life of the project. 427 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 large-

423 40 CFR §146.84(c)(1)(3) and §146.90(d)(1). 424 40 CFR §146.81(d) and §146.84. 425 40 CFR §146.84(b)(2)(iv). 426 40 CFR §146.84(e)(1). 427 40 CFR §146.86(b).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 376 of 786 scale GS including buoyancy, corrosivity, and high sustained pressures over long periods of operation. 428,429 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. 430 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. 431 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.

428 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. 429 40 CFR §146.88. 430 40 CFR §146.90. 431 40 CFR §146.90(j).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 377 of 786 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 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. 432 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. 433 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. 434 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

432 40 CFR §146.90(h)(1) and 75 FR at 77259 (Dec. 10, 2010). 433 40 CFR §146.94. 434 40 CFR §146.85.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 378 of 786 pressure to demonstrate that neither poses an endan germent to

USDWs. 435 The injection well also must be plugged, and follo wing a demonstration of non-endangerment of USDWs by the Class VI owner or operator, the site must be closed. 436,437 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

. 438 Following successful closure, the facility property deed must record that the underlying land is used for GS. 439 The EPA has completed technical guidance documents on Class VI well site characterization, area of review and c orrective action, well testing and monitoring, project plan d evelopment,

435 40 CFR §146.93. 436 40 CFR §146.92. 437 40 CFR §146.93. 438 40 CFR §146.93(b). 439 40 CFR §146.93(c).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 379 of 786 well construction, and financial responsibility. 440,441,442,443,444,445 The EPA has also issued guidance documents on trans itioning Class II wells to Class VI wells; well plugging, po st-injection site care, and site closure; and recordkeeping, rep orting, and data management. 446,447,448,449

440 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 3004.pdf. 441 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 3005.pdf. 442 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 3001.pdf. 443 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 1017.pdf. 444 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816r1 1020.pdf. 445 http://water.epa.gov/type/groundwater/uic/class6/up load/uicfinan cialresponsibilityguidancefinal072011v.pdf. 446 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3004.pdf. See also 40 CFR §144.19 and “Key Principl es 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. 447 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3005.pdf. 448 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3001.pdf. 449 http://water.epa.gov/type/groundwater/uic/class6/up load/epa816p1 3002.pdf.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 380 of 786 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, 20 10)). The EPA has issued Class VI permits for six wells u nder two projects. In September 2014, a UIC Class VI injecti on well 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. 450 Following the operational period, Archer Daniels Mi dland plans a post-injection site care period of ten years. 451 In September

450 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. 451 http://www.epa.gov/region5/water/uic/adm/.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 381 of 786 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. 452 The Alliance proposed to inject a total of 22

million metric tons of CO 2 into an area of review with a radius of approximately 24 miles over the 20 year life of the project, with a post-injection site care period of fifty yea rs. 453 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. 454

452 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. 453 http://www.epa.gov/r5water/uic/futuregen/. 454 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 During Review *** Page 382 of 786 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 that these projects are capable of safely and securely sequest ering large

volumes of CO 2 - including from steam generating units - for long-term storage since the EPA would not otherwise have issued the permits. b. Class II requirements As explained in Section M.3 above, CO 2 has been injected into the subsurface via injection wells for EOR, bo osting production efficiency by re-pressurizing oil and ga s reservoirs and increasing the mobility of oil. There are decad es of industry experience in operating EOR projects. The CO 2 injection wells used for EOR are regulated through the UIC Cl ass II

program. 455 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 enhance d oil or gasrelated 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,

455 40 CFR §144.6(b).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 383 of 786 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. These programs must include permitting, inspection, monitoring, record-keeping, and reporting components. 2. Relevant Requirements of the 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 §60.5555(f). Taken together, these requirements ens ure that the amount of captured and sequestered CO 2 will be tracked as appropriate at project- and national-levels, and th at the status

of the CO 2 in its sequestration site will be monitored, inclu ding air-side monitoring and reporting.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 384 of 786 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

of CO 2 captured and supplied to the economy. 456 CO 2 suppliers are required to report the annual quantity of CO 2 transferred offsite and its end use, including GS. 457 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. 458 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 §60.5555(f) to use the phrase “If your affected uni t captures

456 40 CFR §98.420(a)(1). 457 40 CFR §98.426. 458 40 CFR §98.426(h).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 385 of 786

CO 2 ” in place of the phrase “If your affected unit emp loys geologic sequestration”. This revision is not a cha nge from the

EPA’s initial 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 . 459 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. 460,461,462,463 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. 464 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. 465

459 40 CFR §98.440. 460 40 CFR §98.446. 461 40 CFR §98.448. 462 40 CFR §98.446(f)(9) and (10). 463 40 CFR §98.446(f)(12). 464 See 75 FR at 77263 (Dec. 10, 2010). 465 40 CFR §98.448(a)(1).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 386 of 786 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. 466 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. 467 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. 468 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. 469 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

466 40 CFR §98.448(a)(2). 467 40 CFR §98.448(a)(3). 468 40 CFR §98.448(a)(4). 469 40 CFR §98.448(a)(5).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 387 of 786 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. 470 Under this final rule, any well receiving CO 2 captured from an affected EGU, be it a Class VI or Class II well, must report under subpart RR. 471 As explained below in Section V.N.5.a, a Class II well’s UIC regulatory status does not chan ge because it

receives such CO 2 . Nor does it change by virtue of reporting under subpart RR.

3. UIC and GHGRP Rules Provide Assurance to Prevent , Monitor, and Address Releases of Sequestered CO 2 to Air 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

470 Technical Support Document: “General Technical Sup port Document for Injection and Geologic Sequestration o f Carbon Dioxide: Subparts RR and UU” (Docket EPA–HQ–OAR–200 9–0926), November 2010. 471 See §60.5555(f).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 388 of 786 and Class II injection wells are designed to ensure protection of USDWs from endangerment the practical effect of these complementary technical requirements, as 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 389 of 786 minerals in the formation lead to the precipitation of solid

carbonate minerals.

a. Class VI wells As just discussed in Section V.N.1, the UIC Class V I rule provides a framework to ensure the safety of underg round 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 inject ion 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 V.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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 390 of 786 over the long-term (see above). Site characterizati on requires a detailed assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS sit e to ensure

that wells are sited in suitable locations. 472 Data and information collected during site characterization are used in the development of injection well construction and operating plans; provide inputs for modeling the extent of th e injected CO 2 plume and related pressure front; and establish bas eline information to which geochemical, geophysical, and hydrogeologic site monitoring data collected over the life of the injection project can be compared. 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.

472 40 CFR §146.82(a) and (c).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 391 of 786 Likewise, UIC Class VI mechanical integrity testing requirements are designed to confirm that a well ma intains 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. 473 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

473 40 CFR § 146.94(b )).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 392 of 786 monitoring and other needed actions (including corr ective action). The default duration for the post-injectio n site care 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 we ll requirements protect against releases from all expo sure pathways. Specifically, the EPA stated that the Class 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...”. 474 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

474 79 FR at 353 (January 3, 2014) (Final Hazardous Wa ste Management System: Conditional Exclusion for Carbon Dioxide (CO 2 ) Streams in Geologic Sequestration Activities under subtitle C of RCRA). See Section N.5.c below.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 393 of 786 leakage is developed as part of the subpart RR MRV plan (see Section V.N.2). The MRV plan submitted for subpart RR may 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 394 of 786 example, UIC Class II minimum federal requirements promulgated under SDWA address site characterization, area of r eview, well 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 the atmosphere.

CO 2 injected via Class II wells becomes sequestered by the trapping mechanisms described above in this Section V.N.3. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 395 of 786 additional requirements are necessary and, if so, i nform the design of such regulations. c. Response to 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. 475 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 M.1). The BSER determination and regul atory impact analysis for this rule relies on GS in deep saline formations. 476

475 See, e.g. Comments of Southern Company, p. 41. 476 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 During Review *** Page 396 of 786 However, the EPA also recognizes the potential for sequestering

CO 2 via EOR and allows the use of EOR as a compliance option. 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. 477 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 minimiz ing 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

477 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 397 of 786 rule. This experience has also demonstrated the val ue and efficacy of monitoring programs to determine the lo cation of CO 2 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 398 of 786 required under UIC Class VI rules. The experience a t Sleipner demonstrates that large volumes of CO 2 , of the same order of 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. 478 In 2011, the injection well was modified and inject ion was initiated in a second interval (Stø Formation) in t he field to

478 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 During Review *** Page 399 of 786 increase the storage capacity. Approximately 3 mill ion metric

tons of CO 2 have been injected since 2008. Monitoring 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 Sections V.E.2.a and M, CO 2 from the Great Plains Synfuels plant in North Dakota has bee n injected into the Weyburn oil field in Saskatchewan Canada s ince 2000. Over that time period the project has injected 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. Extensive monitor ing by U.S. and international partners has demonstrated that no leakage has

occurred. The sources of CO 2 for EOR may vary (e.g., industrial processes, power generation); however, this does no t impact the effectiveness of EOR operations (see Section V.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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 400 of 786 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 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. Stora ge 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 401 of 786

and led to the decision to reduce CO 2 injection pressures due to 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 atmosphere. 479

479 “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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 402 of 786 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. 4. 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

served its intended purpose. That is, the monitorin g methods deployed at this site informed the operator of a po tential 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 During Review *** Page 403 of 786 commenter argued that the standard does not require 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). 480 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, a gain

480 Comments of UARG, pp. 37 , - 38.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 404 of 786 requiring further management of the captured pollut ant(s). The EPA is required to consider these potential implica tions in promulgating an NSPS. See section 111(a)(1) (in pro mulgating 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 demons trated” under section 111. See Section V.O below (discussion of t his 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 405 of 786 rigorous, Class VI well requirements in combination with the 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 During Review *** Page 406 of 786 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. 481 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 this comment in more detail in Ch apter 2 of the Response-to-Comment Document. 5. Other Perceived Obstacles to Geologic Sequestrat ion

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

481 Comments of UARG, p. 63.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 407 of 786 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: 482 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

482 “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

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 408 of 786 potential need to transition an 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. 483 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. 484 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 requirement s effectively preclude or substantially inhibit the u se of EOR. The cost of compliance with subpart RR is not signi ficant enough to offset the potential revenue for the EOR operator from

483 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. 484 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 During Review *** Page 409 of 786 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. 485 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 . 486 Thus, the argument that EOR operators will obtain CO 2 from other sources without triggering subpart RR responsibilities, which assumes adequate supplies of

485 Subpart RR costs are presented in 2008 US dollars. 486 “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 During Review *** Page 410 of 786

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. 487 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 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

487 http://www.irs.gov/irb/2009-44_IRB/ar11.html. The section 45Q tax credit for calendar year 2015 is $10.92 per met ric ton of qualified CO 2 that is captured and used in a qualified EOR project and $21.85 per metric ton of qualified CO 2 that is captured and used in a qualified non-EOR GS project

. http://www.irs.gov/irb/2015-26_IRB/ar14.html.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 411 of 786 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. 488 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. 489 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. 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

488 No hazardous waste listings apply to CO 2 streams. Therefore, a CO 2 stream could be identified (i.e. defined) as a haz ardous waste only if it exhibits one or more of the hazard ous characteristics. 79 FR 355 (Jan 3. 2014). 489 79 FR 350 (Jan. 3, 2014).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 412 of 786

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)). 490 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 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

490 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 an impediment to use of anthropogenic CO 2 for EOR.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 413 of 786 ownership of mineral rights, issues of dealing with multiple landowners, lack of state law frameworks, or compet ing,

inconsistent state laws. 491 Other commenters noted the lack of long-term liability insurance, and noted uncertaint ies regarding long-term liability generally. 492 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. 493 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. 494 As noted earlier, both the Archer Daniels Midland (ADM ) and FutureGen projects addressed siting and operational aspects of GS (including issues relating to volumes of the CO 2 and the

nature of the CO 2 injectate) in their permit applications. The

491 See e.g. Comments of Duke Energy, p. 28; UARG, p. 62; AEP, p. 91. 492 See e.g. Comments of UARG, pp. 26, 62; EEI, p. 92; Duke Energy, pp. 27, 28. 493 Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage. 494 http://www.epa.gov/climatechange/Downloads/ccs/CCS -TaskForce-Report-2010.pdf

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 414 of 786 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 demonstration proje ct. AEP noted that although this project was not full scale, find ing a suitable repository, notwithstanding a generally fa vorable geologic area, proved difficult. The company referr ed to years spent in site characterization and digging multiple wells. 495 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. 496 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 V.M). Additionally, since 2007, the USGS has been assessi ng U.S. geologic storage resources for CO 2 . As noted earlier, DOE, in partnership with researchers, universities, and org anizations across the country, is demonstrating that GS can be achieved

495 AEP Comments at pp. 93, 96. 496 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 During Review *** Page 415 of 786 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. 497 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 will require the same number of wells for site char acterization

497 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. A vailable 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 During Review *** Page 416 of 786 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. 498 See also discussion of

this issue in Section V.I.5 above.

O. NonairNon-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 nonairnon-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 nonairnon-air quality impact or energy requirement perspective. 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

498 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 During Review *** Page 417 of 786 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 support. 499 The commenter also references a DOE/NETL report th at

499 See comments of UARG at p. 84 referencing Haibo Zh ai, et al. , Water Use at Pulverized Coal Power Plants with Post -combustion***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 418 of 786 likewise notes significant increases in the amount of cooling and process water required with the use of carbon c apture technology. 500 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 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

Carbon Capture and Storage, 45 Environ. Sci. Technol. , 2479-85 (2011 )). 500 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)

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 419 of 786 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 501

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 of water needed as compared to a similar unit witho ut CCS.

501 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 During Review *** Page 420 of 786 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

would be less than half that for a new SCPC EGU wit h the same net output. 502

502 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 421 of 786 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 503

Generation Gross

Power Auxiliar

y Parasiti

c

Technology Output,

MWe Power,

MWe Demand

(%)

SCPC 580 30 5.2

503 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 During Review *** Page 422 of 786

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. 504 In 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

504 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 During Review *** Page 423 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 424 of 786 at Boundary Dam and for the amine system that will be used at the WA Parish facility. 505 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 options for new power generation. The EPA also note s that the predicted parasitic load for a new NGCC unit would be about 2

505 “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 During Review *** Page 425 of 786 percent - less than half that for a new SCPC EGU wi th the same net output. 506 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 reasonably 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 reduction when compared against the other available emission

506 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 During Review *** Page 426 of 786 reduction options. These are described below. See a lso Section

IV.B.1 above. 1. Highly Efficient Generation Technology (e.g., Su percritical or Ultra-supercritical Boilers) 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 507 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:

507 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 During Review *** Page 427 of 786 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, a newly constructed subcritical PC unit firing bituminous c oal would emit approximately 1,800 lb CO 2 /MWh-g, 508 a new highly efficient SCPC unit using bituminous coal would emit nearly 1 ,720 lb

CO 2 /MWh-g, and a new IGCC unit would emit about 1,430 lb CO 2 /MWhg. 509,510 Emissions from comparable sources utilizing subbituminous coal or lignite will have somewhat highe r CO 2 emissions. 511 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

508 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). 509 “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. 510 The comparable emissions on a net basis are: subcr itical PC – 1,890 lb CO 2 /MWh-n; SCPC – 1,705 lb CO 2 /MWh-n; and IGCC – 1,724 lb CO 2 /MWh-n. (See same references as for gross emissions provided in the text). 511 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 During Review *** Page 428 of 786 power sector. However, most of the recent new power sector projects using solid fossil fuel (coal or petroleum coke) as the primary fuel – both those that have been constructe d and those that have been proposed – are supercritical boilers and IGCC units. About 60 percent of new coal-fired utility b oiler capacity that has come on-line since 2005 was super critical and of the new capacity that came on-line since 2010, a bout 70 percent was supercritical. No new coal-fired utilit y boilers began operation in either 2013 or 2014. Coal-fired power plants that have come on-line most recently include AEP’s John W. Turk, Jr. Power Plant, which is a 600 MW ultra-supercriti cal 512 PC (USCPC) facility located in the southwest corner of Arkansas, and Duke Energy’s Edwardsport plant, which is a 618 MW “CCS ready” 513 IGCC unit located in Knox County, Indiana. Both of

those facilities came on-line in 2012. It is likel y that the units that initiated operation in 2010 or later wer e conceived of, planned, designed, and permitted well before 20 10 – likely in the early 2000s. Thus, it seems clear that the p ower sector had already, at that point, transitioned to the sel ection of supercritical boiler technology as “business as usu al” for new

512 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. 513 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 During Review *** Page 429 of 786 coal-fired power plants. Since that time, there hav e been other coal-fired power plants that have been proposed and almost all of them have been either supercritical boiler desig ns or IGCC units. In Table 1 of the Technical Support Document Fossil FuelFired Boiler and IGCC EGU Projects Under Developmen t: Status and Approach 514 for the January 2014 proposal, the EPA listed the development status of “potential transitional sourc es” (i.e., projects that had been proposed and had received Pr evention of Significant Deterioration (PSD) preconstruction per mits as of April 13, 2012). Of the 16 proposed EGU projects in Table 1 –

most of which have been cancelled or converted to o r replaced with NGCC projects – the majority (nine) are either supercritical PC or IGCC designs. Five of the propo sed 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 opera tions in 2016 and will implement partial CCS to capture approxima tely 65 percent of the available CO 2 , which will be sold for use in EOR operations.

514 Available in the rulemaking docket ID: EPA-HQ-OAR- 2013-0495- 0024.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 430 of 786 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 a chieve emission limitations beyond business as usual and d o so at a

reasonable cost. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 431 of 786 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 V.J and H, additional emissi on 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 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.” 515 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

515 Sierra Club , 657 F.2d at 327 & n. 83.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 432 of 786 explicitly identified in CAA section 111(a)(1), inc luding the

amount of the emission reduction. Under the D.C. Ci rcuit case law, encouraging the development and implementation of advanced control technology must also be considered (and, in any case, may reasonably be considered; see Section V.H.3.d a bove).

Consideration of this factor confirms the EPA’s dec ision not to identify highly efficient generation technology (wi thout 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 generatin g units. CCS technology is also now a viable retrofit option for some modified, reconstructed and existing sources – depe nding upon the configuration, location and age of those source s. As CCS technologies are deployed and used more there is an expectation that, based on previous experience with advanced te chnologies, the performance will improve and the implementation costs will decline. The improved performance and lower costs w ill provide additional incentive for further implementation in the future. The Intergovernmental Panel on Climate Change (IPCC ) recently released its Fifth Assessment report 516 , which recognizes that widespread deployment of CCS is cru cial to reach the long term climate goals. The authors of the rep ort used

516 IPCC, Working Group III, Climate Change 2014: Miti gation of Climate Change, http://mitigation2014.org/report/pu blication //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 433 of 786 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.” 517 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-g, would not serve to promote the increased deployment and implementation of CCS. The commenters argued th at such a

standard could instead have the unintended result o f discouraging the further development of advanced co al generating technologies such as ultra-supercritical boilers an d improved IGCC designs.

517 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 During Review *** Page 434 of 786 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 is not predicated on performance of an advanced control technology wo uld serve to promote development and deployment of that advanced control technology. On the contrary, the history of regulat ory actions

has shown that emission standards that are based on performance of advanced control equipment lead to increased use of that control equipment, and that the absence of a requir ement 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 435 of 786 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 in place. The uncertainty also makes it difficult t o attract partners to help fund the industry’s share. 518 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. The final standard is less stringent than that proposed, and can be met at a lower cost than the proposed standard, and as explained above in Sectio n V.H, the

518 http://www.aep.com/newsroom/newsreleases/?id=1704

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 436 of 786 EPA has carefully evaluated those costs and finds t hem to be reasonable. Further, the record and current economi c conditions (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 . For this reason, the EPA does not find the commenters’ bare assertions that the incremental cost of CCS (particularly as r easonably modulated for this final standard) would make the d ifference between constructing and not constructing new coal capacity to be persuasive. Rather, a cost-reasonable standard r eflecting use of the new technology is what will drive new techno logy 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 new IG CC units, the final standard of performance can be met by co-firi ng a small amount of natural gas. Some commenters argued that IGCC is an advanced technology that, like CCS, should be promo ted. The EPA agrees. IGCC is a low-emitting, versatile technolog y that can be used for purposes beyond just power production (as mentioned just above). Commenters further argued that a requi rement to include partial CCS (at a level to meet the propose d standard of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 437 of 786 performance) would serve to deter – rather than pro mote – more installation of IGCC technology. We disagree with a similar argument that commenters make with respect to parti al CCS for post-combustion facilities, but our final standard moots that argument for IGCC facilities because the final emis sion limitation of 1,400 lb CO 2 /MWh-g will not itself deter installation of IGCC technology, by the terms of th e commenters’ own argument. 2. “Full” Carbon Capture and Storage (i.e., 90 Perc ent 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, we f ound that “full CCS” would certainly result in significa nt CO 2 reductions from any new source implementing the tec hnology. However, we also found that the costs associated wi th implementation, on either a new utility boiler syst em or a new***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 438 of 786 IGCC unit, are predicted to substantially exceed th e costs for other dispatchable non-NGCC generating options that are being considered by utilities and project developers (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 estim ated 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 439 of 786 generating capacity – a competing non-NGCC, dispatc hable 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

nonairnon-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 already 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 440 of 786 may be achieved without geographic constraint, both because 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 hourly increas e in CO 2***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 441 of 786 emissions (mass per hour) of more than 10 percent ( "large" modifications). The EPA is continuing to review the appropriate

standards for modified sources that conduct modific ations resulting in a hourly increase in CO 2 emissions (mass per hour) of less than or equal to 10 percent ("small" modifi cations), is not issuing final standards for those sources in th is action, and is withdrawing the proposed standards for those sources. See

Section XV below. A. Rationale for Final Applicability Criteria for M odified Steam Generating Units Final applicability criteria for modified steam gen erating

EGUs include those discussed earlier in Section III .A.1 (General Applicability) and Section III.A.3 (Applicability S pecific 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 During Review *** Page 442 of 786

constitutes or does not constitute a modification u nder the CAA or the EPA’s regulations. 519 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 hourly CO 2 emissions (mass per hour) of more than 10 percent as compared to the source’s highest hourly emission du ring 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 hourly CO 2 emissions (mass per hour) of 10 percent or less com pared to the source’s highest hourly emission during the previou s 5 years), the EPA is not finalizing any standard or other req uirements, and is withdrawing the June 2014 proposal with resp ect to these sources (see Section XV below).

The effect of the EPA’s deferral on setting standards for

519 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 During Review *** Page 443 of 786 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 for 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

modifications 520 involving fossil steam generating units and

520 NSPS modifications resulting in increases in hourl y emissions of criteria pollutants.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 444 of 786 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 ha ve about past 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 refurbishing or replacement of steam t urbines and other equipment upgrades that result in substantial increases in a unit’s hourly CO 2 emissions rate. The agency has determined, based on its review of public comments and other pu blicly available information, that it has adequate informa tion regarding the types of modifications that could res ult in large increases in hourly CO 2 emissions, as well as on the types of

measures available to control emissions from source s that undergo such modifications, and on the costs and ef fectiveness of such control measures, upon which to establish s tandards of performance for modifications with large emissions increases at

this 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 445 of 786 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 co nsistent with the case law that authorizes agencies to establish a regulatory framework in an incremental fashion, that is, a ste p at a

time. 521 To be clear, the EPA is not reaching a final decisi on as to whether it will regulate modifications with smaller increases, or even that such modifications should be subject t o different requirements than we are finalizing in this rule fo r the

521 As the U.S. Supreme Court recently stated in Massachusetts v. EPA, 549 U.S. 497, 524 (2007): ‘‘“‘ Agencies, like legislatures, do not generally resolve massive problems in one fe ll regulatory swoop; ’’’” and instead they may permissibly implement such regulatory programs over time, ‘‘“‘ refining their preferred 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 ( DCD.C. Cir. 1998), City of Las Vegas v. Lujan, 891 F.2d 927, 935 ( DCD.C. Cir. 1989), National Association of Broadcasters v. FCC, 740 F.2d 1190, 1209–14 (DC Cir. 1984). See also, Hazard ous 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 comp rehensively is not ordinarily a basis for concluding that the r egulations already promulgated are invalid. 'The Agencyagency might properly take one step at a time.' United States B rewers Assoc. v. EPA, 600 F.2d 974,982 (D.C. Cir. 1979). Unless the agency's first step takes it down a path that forecloses mor e comprehensive regulation, the first step is not ass ailable merely because the agency failed to take a second. The steps may be too plodding, but that raises an entirely di fferent issue . . . .").***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 446 of 786 modifications with larger increases. We have made n o decisions and this matter is not concluded. We plan to contin ue to gather information, consider the options for modifications with smaller increases, and, in the future, develop a proposal f or these modifications or otherwise take appropriate steps. 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 refurbishing or replacement of steam turbines a nd other equipment upgrades that would significantly increas e a unit's capacity to burn more fossil fuel, thereby resultin g in large emissions increases. Major upgrades such as these c ould increase a steam generating unit's hourly CO 2 emissions by well over 10 percent. 522 An example of such major upgrade would be work perf ormed at AmerenUE’s Labadie Plant, a facility with four 600- MW (nominal)

coal-fired units located 35 miles west of St. Louis . In the early 2000s, plant staff conducted process improvem ents that raised maximum unit capacity by nearly 10 percent ( from 580 MW

522 See e.g., Power Engineering, Steam Turbine Upgrade s Boost Plant Reliability, Efficiency, available at www.pow ereng.com/articles/print/volume-116/issue-11/features /steamturbine-upgrades-boost-plant-reliability-efficiency .html.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 447 of 786 to 630 MW). 523 Those changes included boiler improvements necessitated by its switch from bituminous to subbi tuminous

coal 524 , installation of low-NO X burners, an overfire air system, and advanced computer controls. One of the performa nce gains came from upgrading all four steam turbines, which AmerenUE chose to replace as modules allowing engineers more freedom to maximize performance unconstrained by the units’ ex isting 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 increase in its power output by 300 MW to 2,400 MW – an increase in capacity of 14 percent. 525 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

523 “Steam turbine upgrading: Low-hanging fruit”, Powe r (04/15/2006), www.powermag.com/steam-turbine-upgrad ing-lowhanging-fruit. 524 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). 525 www.alstom.com/press-centre/2006/10/alstom-signs-p ower-plantupgrade-and-retrofit-contract-with-eskom-in-south-a frica //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 448 of 786 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. 526 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 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 the type s of projects described above, and we are issuing a final standar d of performance for those sources that conduct modifica tions resulting in hourly CO 2 emission increases that exceed that threshold. We are not issuing standards of performa nce for those

526 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 During Review *** Page 449 of 786 sources that conduct modifications resulting in an hourly

increase of CO 2 emissions of less than or equal to 10 percent. Therefore, the EPA is withdrawing the proposed stan dards

for those sources that conduct modifications result ing in a hourly increase in CO 2 emissions (mass per hour) of less than or equal to ten percent and is not issuing final stand ards for

those sources at this time. See Section XV below. U tilities,

states and others should be aware that the differen tiation between modifications with larger and smaller incre ases 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 generating units. There is no similar provision for criteria pollutants or for other sour ce categories. Utilities, states and others should als o be aware that the distinction between large and small modifi cations only applies to NSPS modifications. Sources undertaking modifications may still be subject to requirements of New Source Review under

CAA Title I part C or D (which have different standards for modifications than the NSPS and require a case-by-c ase 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 450 of 786

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 CO 2 hourly emissions. Nevertheless, the EPA expects tha t, to the extent actions undertaken by existing steam generat ing units in response to 111(d) requirements trigger modificatio ns, the magnitude of the increases in hourly CO 2 emissions associated with such modifications would generally be smaller and would therefore generally not subject such modifications to the standards of performance that the EPA is finalizing todayin this

rule for modified steam generating units with larger in creases in hourly CO 2 emissions. 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 EGU’s own best potential performanc e as determined by that source’s historical performance.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 451 of 786 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 EGU’s best demonstrated historical perform ance (in the years from 2002 to the time of the modification) wi th 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 unitspecific emission limit determined by the affected EGU’s best***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 452 of 786 demonstrated historical performance (in the years f rom 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 During Review *** Page 453 of 786

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”. 527 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

527 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 During Review *** Page 454 of 786 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 During Review *** Page 455 of 786 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 and Other Systems of Emi ssion

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 During Review *** Page 456 of 786

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 During Review *** Page 457 of 786 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 commente rs 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 proposed under CAA section 111(d ). We solicited comment on any additional considerations that the EPA should take into account in the applicability of bu ilding blocks two, three and four in the BSER determination. Most commenters stated that building blocks two, three and four sho uld 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 During Review *** Page 458 of 786 reasonable costs, and some opportunity for technolo gical innovation. The proposed emission standard for thes e sources was 1,900 lb CO 2 /MWh-n for units with a heat input rating of greate r than 2,000 MMBtu/h and 2,100 lb CO 2 /MWh-n for units with a heat input rating of 2,000 MMBtu/h or less. The differen ce in the proposed standards for larger and smaller units was based on greater availability of higher pressure/temperature steam turbines (e.g. supercritical steam turbines) for la rger units. As explained in Section III of this preamble, we ar e finalizing the standard on a gross output basis for utility st eam generating units. The equivalent gross-output-based 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-g for large units and 1,800 to 2,200 lb CO 2 /MWhg for small units. We also solicited comment on whe ther the standards for utility boilers and IGCC units should be subcategorized by primary fuel type. In addition, w e solicited comment on if there are sufficient alternate compli ance technologies (e.g., co-firing natural gas) that the small unit subcategory is unnecessary and should be eliminated . Those small sources would be required to meet the same emission standard as large utility boilers and IGCC units.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 459 of 786 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-n and the units' designs are so fundamentally different. Some commen ters said that CFB (due to lower maximum steam temperatures), IGCC, and traditional boilers each need their own subcategory . 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 During Review *** Page 460 of 786

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-g for sources with a heat input rating of greater than 2,000 MMBtu/h and 2,000 lb CO 2 /MWh-g for sources with a heat input rating of 2,000 MMBtu/h or 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 During Review *** Page 461 of 786 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 and Reconstructed Stationary Combustion Turbines This section summarizes the final applicability requirements, BSER determinations, and emission sta ndards for newly constructed and reconstructed stationary comb ustion turbines. In addition, it also summarizes significa nt differences between the proposed and final provisio ns. A. Applicability Requirements We are finalizing BSER determinations and emission standards for newly constructed and reconstructed s tationary combustion turbines that (1) have a base load ratin g for fossil***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 462 of 786 fuels greater than 260 GJ/h (250 MMBtu/h) and (2) s erve a generator capable of selling more than 25 MW-net of electricity to the grid. We also are finalizing applicability r equirements that will exempt from the final standards (1) all s tationary

combustion turbines that are dedicated non-fossil f uel-fired units (i.e., combustion turbines capable of combust ing 50 percent or more non-fossil fuel) and subject to a f ederally enforceable permit condition restricting annual fos sil fuel use to 10 percent or less of a unit’s annual heat input capacity; (2) the large majority of industrial CHP units (i.e ., CHP combustion turbines that are subject to a federally enforceable permit condition limiting annual net-electric sales to the product of the unit’s net design efficiency multipl ied by the unit’s potential output, or 219,000 MWh, whichever is greater); (3) combustion turbines that are physically incapab le of burning natural gas (i.e., not connected to a natural gas p ipeline); and (4) municipal waste combustors and commercial or in dustrial solid waste incinerators (units subject to subparts Eb or CCCC of this part). For combustion turbines subject to an emission stan dard, we are finalizing three subcategories: base load natur al gas-fired units, non-base load natural gas-fired units, and m ulti-fuelfired units. We use the term base load natural gas- fired units to refer to stationary combustion turbines that (1) burn over 90***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 463 of 786 percent natural gas and (2) sell electricity in exc ess of their design efficiency (not to exceed 50 percent) multip lied by their potential electric output. To be in this subcategor y, a stationary combustion turbine must exceed the “natu ral gas-use criterion” on a 12-operation month rolling average and the “percentage electric sales” criterion 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 90 percent natural gas and (2) have net-electric sales equal to or below their design e fficiency (not to exceed 50 percent) multiplied by their pote ntial electric output. These criteria are calculated on t he same rolling average bases as for the base load subcateg ory. Finally,

we use the term multi-fuel-fired units to refer to stationary combustion turbines that burn 10 percent or more no n-natural gas on a 12-operating - month rolling average basis. We are not finalizing the proposed emission standards for modi fied sources and are withdrawing those standards. 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 464 of 786 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 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 and reconstructed base lo ad natural gas-fired combustion turbines, we are final izing an emission standard of 1,000 lb CO 2 /MWh-g, calculated on a 12- operating - month rolling average basis. We are also finalizing an optional emission standard of 1,030 lb CO 2 /MWh-n, 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 c ombustion turbines, we are finalizing a standard of 120 lb CO 2 /MMBtu, calculated on a 12-operating - month rolling average basis. For newly constructed and reconstructed multi-fuel-fire d combustion turbines, we are finalizing a standard of 120 to 16 0 lb***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 465 of 786

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 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

528 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 528***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 466 of 786 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-fuelfired 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 467 of 786 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 “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 gas-***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 468 of 786

fired combustion turbines must meet an emission sta ndard of 1,000 lb CO 2 /MWh-g. Table 16: Proposed Applicability Criteria versus Fi nal Applicability Criteria Applicability Criteria Proposed Applicability Final Applicabilit y Base load rating criterion Base load rating > 73 MW

(250 MMBtu/h) Base load rating > 260 GJ/h 529 (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

529 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 During Review *** Page 469 of 786 efficiency multiplied by potential electric output, or 219,000 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 During Review *** Page 470 of 786 IX. Rationale for Final Standards for Newly Constru cted and Reconstructed Stationary Combustion Turbines

This section discusses the EPA’s rationale for the final applicability criteria, BSER determinations, and st andards of performance for newly constructed and reconstructed stationary combustion turbines. In this section, we present a summary of what we proposed, a selection of the significant co mments we received, and our rationale for the final determina tions, including how the comments influenced 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 applicability criteria based strictly on design and permit restrictions rather than actual operating character istics. Finally, we explain why the proposed percentage ele ctric sales and natural gas-use applicability criteria are bein g finalized instead as criteria to distinguish between separate subcategories of stationary combustion turbines. 1. Proposed Applicability Criteria In the January 2014 proposal, we proposed several applicability criteria for stationary combustion tu rbines. Specifically, to be subject to the proposed emissio n standards,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 471 of 786 we proposed that a unit must (1) be capable of comb usting 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 electric outpu t capacity to a utility power distribution system for sale (that is, to the grid) on a 3-year rolling average; (3) be construct ed for the purpose of supplying and actually supply more 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 rol ling average; and (5) combust over 90 percent natural gas on a 3- year rolling average. We proposed exempting municipal solid wast e combustors

and commercial and industrial solid waste incinerat ors. Under these proposed applicability criteria, two ty pes of stationary combustion turbines that are currently s ubject to criteria pollutant standards under subpart KKKK wou ld not have been subject to CO 2 standards. The first type was stationary combustion turbines that are constructed for the pu rpose of selling and that actually sell 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., non-base load units). The second type was combustion turbines that actually combust 90 percent or less natural gas on a 3-year rolling average basis (i.e., multifuel-fired units).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 472 of 786 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 percentage electric sales criterion would distingui sh between non-base load units (e.g., low capital cost, flexib le, but relatively inefficient simple cycle units) and base load units (i.e., higher capital cost, less flexible, but rela tively efficient combined cycle units). While the proposed applicability criteria did not explicitly exempt simple cycle combustion turbines from the emission standards, we concluded that, as a practic al matter, the vast majority of simple cycle turbines would be excluded because they historically have operated as peaking units and, on average, have sold less than five percent of their potential electric output on an annual basis, well below the proposed onethird electric sales threshold. a. Solicitation of comment on applicability, genera lly We solicited comment on a range of issues related t o applicability. In conjunction with the proposed one -third (i.e., 33.3 percent) electric sales threshold, we solicite d comment on a threshold between 20 to 40 percent of potential e lectric output. We also solicited comment on a variable per centage electric sales criterion, which would allow more ef ficient,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 473 of 786 lower emitting turbines to run for longer periods o f operation before becoming subject to the standards of perform ance. Under this “sliding scale” approach, the percentage elect ric sales criterion would be based on the net design efficien cy of the combustion turbine being installed. In this way, mo re efficient combustion turbines would be able to sell a greater portion of their potential electric output compared with less efficient combustion turbines before becoming subject to an e mission standard. This approach had the benefit of incentiv izing the development and installation of more efficient simp le 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 to eliminate any incentive for generators to install multiple, small, less-eff icient stationary combustion turbines that would be exempt due to their lower output. We further solicited comment on wheth er to provide an explicit exemption for all simple cycle combusti on turbines regardless of the amount of electricity sold. We ad ditionally solicited comment on how to implement the proposed electric sales, fossil fuel-use, and natural gas-use criteri a given that they were to be evaluated as 3-year rolling average s during the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 474 of 786 first three years of operation, and we requested co mment on appropriate monitoring, recordkeeping, and reportin g requirements. We specifically solicited comment on whether these proposed requirements raised implementation issues because they were based on source operation after construction h as occurred. 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 appr oach. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 475 of 786 NSPS applicability approaches that are based on des ign criteria

and include different emission standards for subcat egories that are distinguished by operating characteristics. Spe cifically, we solicited comment on whether we should completely r emove the electric sales and natural gas-use criteria from th e general applicability framework. Instead, the percentage el ectric sales and natural gas-use thresholds would serve as subca tegorization criteria for distinguishing among classes of EGUs a nd subcategory-specific emissions standards. Under thi s broad applicability approach, the “constructed for the pu rpose of” component of the percentage electric sales criterio n would be completely eliminated so that applicability for com bustion turbines would be determined only by a unit’s base load rating (i.e., greater than 260 GJ/h (250 MMBtu/h)) and its capability to sell power to a utility distribution system (i.e ., serving a generator capable of selling more than 25 MW). In c ontrast to the proposed applicability criteria, under the broa d applicability approach, non-base load (e.g., simple cycle) and multi-fuel-fired (e.g., oil-fired) combustion turbi nes would remain subject to the rule regardless of their elec tric sales or fuel use. We solicited comment on all aspects of th is "broad applicability approach," including the extent to wh ich it would achieve our policy objective of assuring that owner s and***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 476 of 786 operators install NGCC combustion turbines if they plan to sell more than the specified electric sales threshold to the grid. 2. Comments on Applicability This section summarizes the comments we received sp ecific to each of the 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 ap proach. Comments on applicability for dedicated non-fossil and CHP units

are discussed in Section III. a. Base load rating criterion Many commenters supported a base load rating of 260 GJ/h (250 MMBtu/h) because it is generally consistent wi th the threshold used in states participating in the Regio nal Greenhouse Gas Initiative (RGGI) and under Title IV programs. Other commenters opposed the proposed applicability thresholds and stated that all new, modified, and reconstructe d units that sell electricity to the grid, including small EGUs and simple cycle combustion turbines, should be affected EGUs because they would otherwise have a competitive advantage in ene rgy markets as they would not be required to internalize the co sts of compliance.

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 477 of 786 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,

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 for simple cycle turbines. These commenters stated that simple cycle turbines are uniquely capa ble of achieving the ramp rates (the rate at which a power plant can increase or decrease output) necessary to respond t o emergency conditions and hourly variations in output from int ermittent renewables. Commenters noted that simple cycle comb ustion turbines serve a different purpose than NGCC power blocks. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 478 of 786 than simple cycle units, economics will drive the u se of NGCC technologies over simple cycle units. However, comm enters also stated that historic simple cycle operating data ma y not be representative of future system requirements as coa l units retire, generation from intermittent renewable gene ration increases, and numerous market and regulatory drive rs impact plant operations. In the absence of a complete exem ption, these commenters supported a percentage electric sales th reshold between 40 to 60 percent of a unit’s potential elec tric output. Some commenters said that because the proposed perc entage electric sales criterion applied over a three-year period, it would adversely affect grid reliability because ope rators conservatively would hedge short-term operating dec isions to ensure that they have sufficient capacity to respon d to unexpected scenarios during future compliance perio ds when the demand for electricity is higher. These commenters were concerned that such compliance decisions would driv e up the cost of electricity as the most efficient new units are taken out of service to avoid triggering the NSPS and older, les s efficient units with no capacity factor limitations are rampe d up instead. Some commenters supported the sliding-scale approac h (i.e., a percentage electric sales threshold based on the design efficiency of the combustion turbine) and stated th at incentives for manufacturers to develop (and end users to purc hase) higher***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 479 of 786 efficiency combustion turbines could help mitigate concerns about a monolithic national constraint on simple cy cle capacity

factors. In contrast, others commented that fast-start NGCC units intended for peaking and intermediate load applicat ions can achieve comparable ramp rates to simple cycle combu stion turbines, but with lower CO 2 emission rates. These commenters said that simple cycle turbines should be restricte d to their historical role as true peaking units and that the proposed onethird electric sales threshold provided sufficient flexibility. Some commenters suggested that the one-third electr ic sales threshold could be reduced to 20 percent or lower w ithout adverse impacts on grid reliability. Commenters noted that a complete exclusion for simp le cycle turbines would create a regulatory incentive for ge nerators to install and operate less efficient unaffected units instead of more efficient affected units, thereby increasing C O 2 emissions. According to these commenters, any applicability di stinctions

should be based on utilization and function rather than purpose or technology. Commenters in general supported the use of 3-year r olling averages instead of a single-year average for the p ercentage and total electric sales criteria because, in their vie w, the 3-year rolling averages would provide a better overall pic ture of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 480 of 786 normal operations. Some commenters stated that a ro lling 12- month or calendar-year average could be severely sk ewed in a given year because of unforeseen or unpredicted eve nts. They said that using a 3-year averaging methodology woul d provide system operators with needed flexibility to dispatc h simple cycle units at higher than normal capacity factors. In contrast, some commenters stated that, because capacity is fo rward-looking (e.g., payments for capacity are often made several years in advance), the 3-year averaging period provides limi ted benefit because owner/operators need to reserve the ability to respond

to unforeseen events. Commenters noted that potential compliance issues c ould

result from the inconsistent time frame between the 3-calendaryear applicability period and the 12-operating-mont h compliance period. For example, a facility could sell more tha n one-third of its potential electric output over a 3-year peri od, but sell less than one-third of its potential electric outpu t during any given 12-operating - month compliance period within that 3-year period. During a 12-operating - month period with electric sales of less than one-third of potential electric output , a unit could be operating for long periods at part load an d have multiple starts and stops. These operating conditio ns have the potential to increase CO 2 emissions, regardless of the deign***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 481 of 786 efficiency of the turbine. Therefore, a unit could have aman emission rate in excess of the proposed 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 system emergency from counting towards net sales. T hese commenters stated that the exclusion was appropriat e because the benefits of operating these units to generate elect rical power during emergency conditions would outweigh any adve rse impacts

from short-term increases in CO 2 emissions. One commenter stated that, in addition to declared grid emergencies, oth er 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 system emergencies when calculating a source's percentage electric sales for applicability purposes because NSPS must apply continuously, even during system emergencies. These commenters stated that the EPA does not have the authority und er the CAA to suspend the applicability of a standard during peri ods of system emergency. Some commenters stated that an exclusion would be unnecessary because the EPA Assistant Administrator for Enforcement has the authority to advise a source th at the government will not sue the source for taking certa in actions***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 482 of 786 during an emergency. Commenters said that this enfo rcement discretion approach has provided prompt, flexible r elief that is tailored to the needs of the particular emergency a nd the communities being served and is only utilized where the relief will address the particular emergency at hand.

Commenters added that this enforcement discretion a pproach

is consistent with the CAA’s mandate that emission limits apply continuously and provide safeguards against abuse. One commenter stated that emergencies happen rarely and typically last for short periods, that the proposed percentage electri c sales threshold would allow a source to operate at its fu ll rated capacity for up to 2,920 hours per year without tri ggering applicability, and that the potential occurrence of grid emergencies would represent a tiny fraction of this time. Another commenter stated that no emergency short of large scale destruction of power generating capacity by terrori sm, war, accident, or natural disaster could justify operati ng a peaking unit above a 10-percent capacity factor on a 3-year rolling

average. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 483 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 484 of 786 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. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 485 of 786 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

Based on our consideration of the comments received related to the proposed applicability criteria and practica l implementation issues, we are revising how those cr iteria will be implemented. The final applicability criteria fo r combustion 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 the combustion turbine's base load rating and the combustion turbine's total electric sales capacity. The final general applicability framework also includes multi ple exemptions that are relevant to combustion turbines : combustion turbines that are not connected to natural gas pipe lines; CHP facilities with federally enforceable limits on tot al electric sales; dedicated non-fossil units with a federally enforceable***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 486 of 786 limits on the use of fossil fuels; and municipal wa ste

combustors and incineration units. The final applicability framework reflects multiple variations from the proposal that are responsive to public 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 propose d 219,000 MWh total electric sales criterion. Finally, we are eli minating the proposed “constructed for the purpose of” qualifier for the total and percentage electric sales criteria. We ar e also not finalizing CO 2 standards for dedicated non-fossil fuel-fired or

industrial CHP combustion turbines. The rationale f or not finalizing CO 2 standards for dedicated non-fossil and industrial

CHP units is discussed in more detail in Section II I. The EPA agrees with commenters that the NSPS applic ability framework should be structured so that permitting a uthorities, the regulated community, and the public can determi ne what standards apply prior to a unit having commenced co nstruction. With this in mind, the EPA has concluded that the p roposed fossil fuel-use, natural gas-use, percentage electr ic sales, and total electric sales applicability criteria for com bustion turbines are not ideal approaches. Because applicab ility***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 487 of 786 determinations based on these criteria could change from year to year (i.e., units could move in and out of coverage each year depending on actual operating parameters), some ope rators would not know the extent of their compliance obligations until after the compliance period. Further, from a practical implementation standpoint , existing permitting rules generally require pre-con struction permitting authorities to include enforceable condi tions limiting operations such that unaffected units will not trigger applicability thresholds. Such conditions are often called “avoidance” or “synthetic minor” conditions, and th ese conditions typically include ongoing monitoring, re cordkeeping, and reporting requirements to ensure that operation s remain below a particular regulatory threshold. The following sections provide further discussion o f the final general applicability criteria and the ration ale 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 488 of 786 (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.

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 489 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 490 of 786 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 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 491 of 786 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 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 492 of 786 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). The EPA cannot finalize emission guidelines for exi sting sources under 111(d) unless the EPA has promulgated emission standards that would apply to those sources if they were new pursuant to 111(b). Under the second permitting approach we considered, units with low electric sales would be excluded from 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 493 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 494 of 786

detail in Section IX.B .2 , we are finalizing the sliding-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 two approaches for implementing the inten t of the proposed natural gas-use criterion (i.e., to exclud e non-natural gas-fired combustion turbines) through operating pe rmit restrictions. Under the first approach, an emission standard would apply to all combustion turbines with a permi t restriction mandating that natural gas contribute over 90 perce nt of total heat input. 530 Under the second approach, an emission standard would apply to all combustion turbines without a pe rmit restriction limiting natural gas use to 90 percent or less of total heat input. 531 As with the percentage electric sales

530 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. 531 This approach could also be written as “an emissio n standard would apply to all combustion turbines without perm it***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 495 of 786 criterion, the first approach is not practical beca use combustion turbines could avoid applicability by si mply not having a permit that requires the use of more than 90 percent natural gas, even if they intend to only burn natur al gas. We disregarded this approach because it would essentia lly provide a pathway for all NGCC units to avoid applicability u nder both 111(b) and 111(d). The second approach is problemat ic because operating permit restrictions to improve air qualit y are typically written to limit high emission activities (e.g., limiting the use of distillate oil to 500 hours ann ually), not to limit lower emitting activities. This approach c ould lead to perverse environmental impacts by incentivizing the use of nonnatural gas fuels, which would typically result in higher CO 2 emissions. Furthermore, the second approach would n ot limit the fuels that can be burned by affected units (i.e., c ombustion turbines not required to use non-natural gas fuels) and would

continue to cover combustion turbines even when the y burn over 10 percent non–natural gas fuels. Because all non-n atural gas fuels except hydrogenH 2 have CO 2 emission rates higher than natural gas, this approach would exacerbate the con cerns raised by commenters about the achievability of the 111(b) requirements when burning backup fuels.

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 During Review *** Page 496 of 786 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 applicabili ty approach. The EPA has concluded that the only practical appro ach to implement the natural gas-use criterion is to look at the turbine’s physical ability to burn natural gas. The refore, we are not finalizing CO 2 standards for combustion turbines that are not capable of firing any natural gas (i.e., not co nnected to a natural gas pipeline). From a practical standpoint, the burners

of most combustion turbines can be modified to burn natural gas, so this exemption is essentially limited to combust ion turbines

that are built in remote or offshore locations with out access to natural gas. Consistent with the broad applicabilit y approach, we are finalizing standards for all other combustio n turbines, but are subcategorizing between natural gas-fired t urbines and multi-fuel-fired turbines. Specifically, and as exp lained in

more detail in Section IX.B .3 , we are distinguishing between these classes of turbines based on whether they bur n greater than 90 percent natural gas or not. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 497 of 786 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 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 operationssales -based subcategories , such as base load

and peaking units; our rationale for adopting operations-based subcategories; and the appropriate thresholdssliding scale to distinguish between such subcategories. Finally, it describes comments we received regarding fuel-based subcatego ries and our rationale for adopting fuel-based subcategories. We are finalizing a variation of the broad applicability a pproach where the percentage electric sales and natural gas-use c riteria serve***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 498 of 786 as thresholds that distinguish between subcategorie s of

combustion turbines. 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 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

versusand less efficient combustion turbines, but rather wou ld divide the units into arbitrary size classification s. These commenters suggested that 1,500 MMBtu/h would be a better cutpoint because (1) based on data reported to Gas Turbine World (GTW ),) showed that new combustion turbines are not currently offered with a heat input rating between 1,300 MMBt u/h and 1,800 MMBtu/h and (2) this, so the higher cut-point would more***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 499 of 786 accurately reflects when more efficient technologie s 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 turbine engine operating temperature, increase the turbine engine pressure ratio, and usingor add multi-pressure steam and a steam reheat cycle). These commenters also said that separate st andards for small and large turbines would undermine the incent ive for technology innovation, which they described as a ke y purpose of the NSPS program, and that relaxing standards for s maller units

willwould discourage investment in more efficient technologi es, resulting in increased CO 2 emissions. These commenters recommended that the limit for both large and small units be no higher than 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. 532

532 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 500 of 786 However, sinceBecause the heat input from duct burners is necessary to accurately determine the potential electric output,

our definition of “ base load rating ” includes the heat input from any installed duct burners. The EPA reviewed t he heat input data for existing NGCC units that has been submitte d to the EPA’s Clean Air Markets Division (CAMD).CAMD. These data 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 has concluded that the regulated community uses various sizes of NGCC turbines and when the heat input from duct burners is includ ed, there is

no absolute clear break between the NGCC unit sizes of NGCC

units that could distinguishesdistinguish between small and large units. In fact, subcategorizing by size could unduly influence the development of future NGCC offerings because manufacturers could be incentivized to design new p roducts at the top end of the small subcategory to take advant age 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

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 During Review *** Page 501 of 786 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- onto -one configuration NGCC power block with a base load rating of 1,500 MMBtu/h or less h as a design emission rate of the 767 lb CO 2 /MWh-n (984 MMBtu/h). The

most efficient one- onto -one configuration NGCC power block with a base load rating just greater than 1,500 MMBtu/h has a design

emission rate of 772 lb CO 2 /MWh-n (1,825 MMBtu/h). SinceBecause

the smaller unit has a lower design emission rate than the larger unit, this contradicts the rationale for increasing the

cut - point does not make sense

. Finally, the EPA has concluded that, while certain smaller NGCC designs aremay 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 502 of 786 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. For all of these reasons, we have decided against subcategoriz ing

combustion turbines based on size. Our rationale for 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 in the applicability section, the fina l applicability does not include exemptions for non-C HP units based on either actual electric sales or permit res trictions limiting the amount of electricity that can be sold . This section describes the comments we received regardin g subcategorizing based on percent electric sales, ou r response to those comments, and the final percent electric sale s subcategorization. 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 503 of 786

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 “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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 504 of 786 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, cycling/load-following/ intermediate

load , and base load units. These commenters said that e ach of the three subcategories subcategory should be distinguished by annual hours of operation and that each should have a different

BSER and emission standard. In general, these commenters suggested that the BSER for peaking units should be simple cycle combustion turbines, the BSER for the middle catego ry should be high-efficiency aeroderative simple cycle or fast-s tart NGCC combustion turbines, and the BSER for base load uni ts should be highly efficient NGCC combustion turbines. Other commenters opposed the tiered approach. These commenters said that separate standards for differe nt operating conditions would be complicated to implement and en force, while providing few benefits. These commenters said that a tiered approach could also have the unintended consequence of encouraging less efficient technologies and less efficient operation because it would create a regulatory incentive to install lower-capital-cost, less-efficient units th at would operate under the percentage electric sales thresho ld instead of higher-capital-cost, more-efficient units that woul d operate

above the threshold. They added that 12-operating-month capacity***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 505 of 786 factors vary significantly for both simple cycle an d NGCC

combustion turbines. These commenters stated that r eal-world variability and uncertainty significantly diminishe s the value of creating tiered standards for peaking and load-f ollowing units because individuals responsible for long-rang e decisions related to reliability may react to a system of tie red standards by purchasing additional generating assets to ensur e system demand can be satisfied while operating individual units below tier-specific percentage electric sales thresholds. After evaluating these comments, the EPA has conclu ded that it is appropriate to adopt a two-tiered subcategory subcategorization approach based on a percentage electric sales threshold to distinguish between non-base load (e.g., and base load units. While we agree with commenters that sep arate

standards for peaking, cycling, and intermediate /load-following units), and base load units . While multiple commenters supported is attractive on the surface, we ultimately conclud ed that a three-tiered approach is not appropriate for several reasons. First, the increased generation from renewable sour ces that is anticipated in the coming years makes it very diffi cult to determine appropriate thresholds to distinguish amo ng peaking, intermediate, and base load subcategories. Indeed, the boundaries between these demand-serving functions m ay blur or shift in the years to come. The task is further com plicated***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 506 of 786 because each transmission region has a different mi x of generation technologies and load profiles with diff erent 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 507 of 786

rate. For all of these reasons , the EPA has concluded that we do

not have sufficient information at this time to either (1) identify a separate BSER or (2) establish an outputthree sales

based standard for other than non-base load and base load subcategories. 533 Instead, as we explained above, we are finalizing t wo sales-based subcategories. To determine an appropriate 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 peakingnon-base

load units, low capital costs and the ability to start , stop,

and stopchange load quickly to meet increased demand are key. Simple cycle combustion turbines meet these criteri a and thus compriseserve the bulk of peaking unitspeak demand . In contrast, for base load units, efficiency is the key consider ation, while capital costs and the ability to start and stop qui ckly are less important. While NGCC units have relatively high ca pital costs and are less flexible operationally, they are more efficient than simple cycle units. NGCC units recover the exh aust heat from the combustion turbine with a HRSG to power a steam turbine, which reduces fuel use and CO 2 emissions by

533 We have concluded it is not possible to identify a ppropriate subcategorization criteria for cycling, load-follow ing, or intermediate load units. The broad non-base load an d base load subcategories include these units.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 508 of 786 approximately one-third compared to a simple cycle design. Consequently, the majority of base load units use NGCC technology. Because simple cycle turbines have lower

efficiencies and cannot achieve the same emission r ates as NGCC combustion turbines and because they serve a differ ent primary rolehistorically been non-base load units , we have concluded that it is appropriate to distinguish between the n on-base load and base load subcategories in a way that recognize s 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 role of dedicated peakingdistinction between non-base load and base l oad units is unclear. For example, some commenters indicated tha t increased generation from intermittent renewable sources has created a perceived need for additional cycling and load following generation that will operate between the traditiona l roles of peaking and base load units. As stated above, simple cycle combustion turbines historically have served peak d emand, while NGCC combustion turbines have operated at base load . The need to back up intermittent renewables has blurredTo fulfi ll this distinction. For exampleperceived need , some manufacturers have developed high - efficiency simple cycle turbines. These high - efficiency turbines have higher capital costs than

oldertraditional simple cycle turbine designs, but maintain***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 509 of 786

similar flexibilities (e.g., , such as the ability to start , stop, and change load rapidly ).. Other manufacturers have developed fast-start flexible NGCC turbines to fill the same role. These newer NGCC designs have lower design ef ficiencies

than NGCC designs intended to only operate as base load NGCC designsunits , but are able to start up more quickly to respond to rapid changes in electricity demand. As a result of these new technological developments, both high - efficiency simple cycle

and fast-start NGCC units can be used for tradition al peaking applications, as well as for higher capacity applications, such as supporting the growth of intermittent renewable generation

. Importantly, these newer technologies are both sign ificant potential sources of CO 2 emissions, and we have concluded that it is appropriate that they should be subject to a CO 2 emission

standard

. With the changing electric sector in mind, we attemptedset

out to identify a potential an appropriate percentage electric

sales threshold for to distinguish between non-base load and

base load natural gas-fired non-base load units. To do this, we

evaluated the annual electric sales Two factors wer e of existing simple cycle combustion turbines from the period of 2005 to 2014. We triedprimary importance to identify a our decision. First, the threshold that wouldneeded to be high enough to subcategorize address commenters’ concerns about th e need to***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 510 of 786 maintain flexibility for simple cycle units to supp ort the majority of simple cycle turbines operating at hist orical capacities, yet growth of intermittent renewable ge neration. Second, the threshold needed to be low enough to avoid including high efficiency simple cycle units and fast-start N GCC units in this subcategory. We also tried to avoid setting a threshold that would createcreating a perverse incentive for owners and operators to avoid applicabilitythe base load subcategory by installing multiple, less efficient turbines instea d of fewer,

more efficient turbines. While 88 percent of existing simple cycle units did not have annual electric sales that exceeded 10 percent of their potential electric output between 2005 and 2014, we believe this value is too low for a practical threshold. Many co mmenters objected to the proposed one-third electric sales t hreshold, so few, if any, owners or operators would consider a 1 0 percent threshold sufficiently flexible to accommodate new peaking and cycling units. In addition, our cost models show th at it would

not be cost-effective to install a NGCC combustion turbine that would operate at a capacity factor near 10 percent. The EPA also considered a percentage electric sales threshold of 25 percent for non-base load units. Ni nety-eight percent of existing simple cycle turbines did not e xceed this level of sales between 2005 and 2014. In addition, at this level***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 511 of 786 of electric sales, our cost models indicate that it would be

cost-effective to install a NGCC combustion turbine . Finally, we think that it is possible that the few existing sim ple cycle units that had electric sales in excess of 25 perce nt were operating during a system emergency, meaning some o f those sales would not count towards determining exceedance of t he threshold. This level is further supported by the permit restr iction for the CPV Sentinel facility in Desert Hot Springs, Ca lifornia. This facility consists of eight high-efficiency int ercooled simple cycle turbines intended to support wind gene ration in California. Each unit at this facility is restricte d to 2,500 hours of operation annually. Assuming an average du ty cycle of 90 percent, this is equivalent to an annual percent age electric sales restriction of approximately 25 percent. Similar to the 10 percent threshold, however, the E PA acknowledges that owners and operators of new simpl e cycle turbines would generally not elect to avail themsel ves of a 25- percent sales restriction for multiple reasons. Fir st, many commenters stated that existing simple cycle turbin es are permitted to operate 2,920 hours or more annually t o respond to variable annual demands and provide capacity reserv e in the event of a system emergency. The commenters stated that, due to the changing nature of the grid (e.g., increased ge neration from intermittent renewable generation), these needs wil l increase in***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 512 of 786 the future. Additionally, the EPA has concluded tha t this level is too low to avoid potential adverse environmental impacts. Utilities have an obligation to provide sufficient electricity to meet system demand regardless of specific emissi on standards that have been placed on individual units. By limit ing non-base load units to less than 25 percent of their potenti al electric output before the base load standard would take eff ect, utilities and other developers could decide to buil d multiple, lower-capital-cost, less-efficient simple cycle rat her than fewer, higher-capital-cost, more-efficient simple c ycle or faststart NGCC units. The overall CO 2 emissions (and the cost to ratepayers) would be higher for a scenario with mul tiple combustion turbines operating at lower loads than a scenario with fewer, more efficient units. Based on concerns raised in comments about the impa ct of intermittent renewable generation (e.g., wind and s olar) on the future operation of peaking and cycling units, the EPA has done additional analysis. First, we tried to get a more accurate picture of how many existing simple cycle turbines 534 would exceed the proposed one-third percentage electric s ales threshold based on historical operation. We also ex amined the operationTo determine the potential impact of inter mittent

534 We are using simple cycle turbine operation to app roximate the operation of all peaking units.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 513 of 786 renewable generation on the operation of simple cyc le units, we examined the average electric sales of simple cycle turbines in the lower 48 states between 2005 and 2014 using inf ormation

submitted to the EPA CAMD. Finally, we reviewed the recent operating history of simple cycle turbines in regio ns with relatively large amounts of wind and solar generati on. In the proposal, the EPA estimated the number of ex isting simple cycle turbines that would have exceeded the proposed onethird percentage electric sales threshold (i.e., 33 .3 percent) by looking to see whether they operated over 2,920 hours in any given year. However,We combined this method overestimated the number of simple cycle turbines that would have exc eeded the threshold in two ways. First, it did not account fo r hours in which simple cycle turbines were operating at part load. The typical duty cycle (i.e., average capacity factor w hile operating) of simple cycle turbines is approximatel y 70 percent. Therefore, simple cycle turbines can operate in exc ess of 2,920 hours and still not sell one-third of their potenti al electric output to the grid. Historically, simple cycle turb ines sell approximately 3 percent of their potential electric output, and only 10 of the 1,939 existing simple cycle turbines have individual years where the percentage of electric s ales exceeded one-third of their potential electric output. Secon d, we proposed to calculate the percentage electric sales criterion on***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 514 of 786

a 3

- year rolling average basis. Using a 3-year rolling average, only two existing simple cycle turbines historicall y sold enough electricity to exceed the proposed one-third percen tage electric

sales threshold.

We useddata with information reported to the Energy Information Administration ( EIA ) to determine the impact of renewable generation on the operation of simple cyc le turbines. The EIA provides data on total in-state electricity generation, including wind and solar, from 2008 through 2014. Interstate flow of electricity data is available from 2008 thr ough 2012. Specifically, we examinedWe focused on data from the Southwest Power Pool (data approximated by EGUs in Nebraska, Kansas, and Oklahoma), Texas, and California , all. All of which hadthese regions have relatively large amounts of generation from wind and solar and experienced increases forin the percent of wind and solar electricity generated in-state and percen tportion of total electric generation fromprovided by wind and solar fromduring the 2008 through - 2014 . To determine the impact, if any, of the increased generation from intermittent renewable sources on simple cycle turbine capacity factors, t he EPA reviewed data submitted for simple cycle turbines t o the EPA’s

CAMD over the same time period.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 515 of 786

a. Southwest power poolPower 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 electric sales from simple cycle turbines o nly increased at an annual rate of 1.7 percent, and remained esse ntially unchanged at 3 percent of potential electric output 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 generation and that simple cycle turbines are not n ecessary to***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 516 of 786 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 2014. The average growth rate of wind and solar was 13 percent,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 517 of 786

while the overall demand grew at an average rate of 2 percent annually. Similar to the Southwest Power Pool, the overall percent ofaverage 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 output from simple c ycleof these

turbines actually decreased at an annual rate of 1.1 percent. However, the overallTotal generation from simple cycle

combustion turbines increased at an annual rate of 6.6 percent , resulting from however, 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. Focusing on these simple cycle

combustion turbines installed in the particular transmission regionwill address concerns raised by commenters ab out the future percentage electric sales of highly efficien t simple cycle turbines and give an indication of the impact of increased renewable generation on non-base load units intende d to backup***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 518 of 786

wind and solar . There are two highly efficient intercooled simple cycle turbines installed in Texas. These two combustion turbines sell an average of 10 percent of their pot ential electric output annually, compared to an average of 3 percent for the remaining simple cycle turbines. 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 providing firm capacity for intermittent generation sources s uch 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 similar to as they have historically and sell less than one-third 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 significantly than in the other evaluated regions. AverageThe

average electric sales relative to potential electric output from simple cycle turbines increased from 5.1 to 5. 9 percent, an***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 519 of 786 annual rate increase of 4.5 percent. As in Texas, c onsiderable additional simple cycle capacity has been added in recent years.

The averagetotal capacity of simple cycle turbines is increasing at 15 percent annually even though overall demand h as remained relatively steady. In addition, the newest simple c ycle turbines are operating at higher capacity factors than the e xisting fleet of simple cycle turbines, resulting in an average i ncrease in generation from simple cycle turbines of 21 percent . Many of the new additions are intercooled simple cycle turbines that may have been installed with the specific intent to bac k up wind and solar generation.

The annualaverage electric sales relative to the potential electric output for the intercooled turbines rangeranged from 3 to 25 percent, with a 7 percent average. No simple cycle

turbines in California have sold more than one-thir d of their potential electric output on an annual basis. The o peration of simple cycle turbines that existingexisted prior to 2008 havehas not changed significantly. Average electric sales relative to potential electric output for these simple cycle turbines increased at an annual rate of 0.1 percent. This is an

indicationindicates that support for additionalnew renewable generation is being provided by new units and not b y the installed base of simple cycle units. These units a re still***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 520 of 786 serving their historical role of providing power du ring peak periods of demand.

Based on historical amounts of intermittent generationour data analysis , the proposed percentageone-third electric sales threshold would appear to offer sufficient operatio nal flexibility for new peaking (i.e., simple cycle ) combustion turbines. Existing NGCC units, other generation ass ets, and

demand - response programs are currently providing adequate backup to intermittent renewable generation. In the future, however, existing NGCC units will likely operate at higher capacity factors. They will therefore be less avail able to provide backup power for intermittent generation. I n addition,

the percentamount of power generated fromby intermittent sources is expected to increase in the future. Both of thes e factors could require additional flexibility from the remai ning generation sources to maintain grid reliability. When attempting to determine an emission rate for u nits actually providing this middle tier of service stri ctly based on technology, we have concluded there is significant overlap. In addition, we do not have specific cost information on either high efficiency aeroderivative turbines or rapid st art combined cycle units relative to conventional simple cycle o r combined cycle units so we cannot take cost effectiveness in to account. Regardless, as described earlier, for combustion tu rbines***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 521 of 786 operating above this threshold it is cost effective and the BSER is the addition of heat recovery to the turbine exh aust. Further, the EPA has concluded that even if we were able to establish an appropriate technology based BSER subcategorization, we do not have sufficient inform ation to establish an appropriate emission standard for a mi ddle tier category. For example, in the transition from peaki ng to base load operation (i.e., cycling and intermediate load ), combustion turbines may have similar percent electric sales, b ut their operating characteristics can differ significantly. For example, though they may have similar annual percent electri c sales, one unit might have relatively steady operation (i.e., less starts and stops and more operation near full load) and th e other could have variable operation (i.e., frequent starts and stops and significant operation at part load). This method of operation

can result in increased CO 2 emission rates and the amount of increase depends on the specific technology install ed. Taking these considerations into account, the EPA has conc luded that we

do not have sufficient information at this time to establish an appropriate emission standard for a middle tier sub category. Even though fast - start combined cycle technologiesNGCC

units , reciprocating internal combustion engines, energy storage technologies, and demand - response programs are promising technologies for providing backup power for renewab le***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 522 of 786 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 CO 2 benefits of these technologies compared to simple cycle turbines, the EPA has concluded at thi s time that it is appropriate to finalize an NSPSa percentage electric sales

threshold that provides additional flexibility for new non-base load combustionsimple cycle turbines intended to run at lower capacity factors. . The EPA considered multiple options for extending flexibility for non-base load units and accounting for impacts on efficiency due to cycling operations. Ultimately Specifically ,

we have concluded that a trigger percentage electric sales

threshold based on thea unit’s design net efficiency at standard conditions is appropriate. The percentage electric sales threshold for classification within the base load ( i.e., NGCC) subcategory would be based on the design net effici ency of the

unit. The EPA has concluded that This is the slidin g-scale approach on which we solicited comment. Several com menters supported this approach because it provides sufficient operational flexibility for new non-base load (i.e., simple cycle and fast response combined cycle)-start NGCC combustion***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 523 of 786

turbines , even with increased future use. In addition, even though the historical percentage electric sales of simple cycle turbines is less than 5 percent, this sliding scale subcategorization approach based on the unit-specif ic net efficiency and simultaneously promotes the installation of the most efficient generating technologies since operational flexibility will be directly linked to the efficien cy of the unit. . By allowing more efficient turbines to sell more electricity before becoming subject to the standard for the base load subcategory, the sliding scale should reduce t he perverse incentive for owners and operators to install more lowercapital-cost, less-efficient units instead of fewer highercapital-cost, more-efficient units. At the same tim e, the sliding scale should incentivize turbine manufactur ers to design higher efficiency simple cycle turbines that 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 unitsdesigns . These efficiency values follow the methodology th e***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 524 of 786 EPA has historically used and are based on the high er heating value (HHV) of the fuel. In contrast, combustion turbine vendors in the United

StatesU.S. often quote efficiencies based on the lower heatin g value (LHV) of the fuel. The LHV of a fuel is deter mined 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 lo wer than the HHV. Therefore, the corresponding LHV efficiency ra nges would be 35 to 44 percent for aeroderivative designs and 33 to 40 percent for frame designs. We considered basing the percentage electric sales

threshold on both the higherHHV and lower heating value efficiency.LHV. The EPA typically uses the higher heating

valueHHV , but in light of comments expressingcommenters’ concerns regarding uncertainty in the operation of non-base load units in the future, we opted to be conservative an d use the lower heating value efficiency. During the next rev iew of the EGU GHG NSPS, the EPA anticipates that fast-start/r apid-response combined cycle technologies, energy storage technol ogies, and demand response programs will be further developed, and we will re-evaluate lowering the percent electric sales thr eshold. LHV efficiency.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 525 of 786 Based on comments, we We anticipate the aeroderivative that high-efficiency simple cycle and fast-start NGCC turbines will make up the majority of new combustion turbinescapacity intended

for non-base load use (e.g., peaking) applications. Based on the sliding - scale threshold approach, owners / and operators of new simple cycle combustion turbines wouldwill be able to sell between 35 to 44 percent of the turbine’s potential electric output to avoid complying with the standards in this rule making. Based on historical operation of simple cycle turbi nes, . Our analysis showed that 99.5 percent do not sellof existing simple cycle turbines have not sold more than one-third of their potential electric output on an annual basis. Therefore, the majority of new simple cycle applications would not be significantly impacted how they would operate absen t the requirements of this rulemaking. In addition, 99.9 percent of existing simple cycle turbines operate lesshave not sold more than 36 percent of their potential electric output on an annual basis. Owners/operators of new simple cycle combustion turbines would still have multiple technology options available to them to ac commodate this amount of operation. The two simple cycle turbines that exceeded the 36 percent threshold had annual percent electric sales of 39 and 45 percent and are located in Monta na and New

York , respectively. As noted earlier, the most efficient simple***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 526 of 786 cycle turbine currently available is 44 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 thr eshold , of 44 percent, which is based on current simple cycle designs (i.e., 44 percent),, sold an abnormally high amount of electricity in 2014. It is possible that this unit was operating under emergency conditions , and. As explained below, the incremental generation due to the emergency would n ot have been counted against the totalpercentage electric sales subcategorization threshold. We are capping the totalpercentage electric sales threshold at 50 percent of the potential electric output for multiple reasons. First, the definition of stationary combustion turbine includes both simple and combined cycle units. Thou gh combined cycle unit design efficiencies often exceed 50 perc ent, the EPA

has concluded that theNGCC emission rate isrates are relatively steady above this level of 50 percent electric sales, andso

there is no reason that the same output a NGCC unit with sales greater than this amount should not have to comply with the output- based standard should not apply.for the base load subcategory. Second, the design net design efficiency of the flexible combined cycle unitfast-start NGCC units intended as an option for peaking and intermediate load applications is 49***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 527 of 786 percent. As described earlier, this technology can serve the same purpose as high - efficiency aeroderivative simple cycle

turbines. SettingIf we were to set a cap any lower than 50 percent , it could have the perverse impact of incentivizing the installation of less efficient technologiescreate a disincentive for owners and operators to choose this promising n ew technology

. As mentioned previouslyFinally , the EPA solicited comment on excluding electricity sold during system emergen cies asfrom counting toward percenttowards the percentage electric sales

threshold. WeAfter considering the comments, we have concluded

that the emergency conditions exemption providesthis exc lusion is necessary to provide flexibility to, maintain system reliability , and minimizesminimize overall costs to the sector. We disagree with commenters that suggested that the EPA’s existing enforcement discretion should be used in place of specifying how electricity generated during system emergencies should be accounted for. Including this provision p rovideswould

be a viable alternative. An enforcement discretion- based approach would not provide certainty forto the regulated community, public, and regulatory authorities on the applicability of the emission standards . System emergencies , which is a primary reason why we are finalizing the broad applicability approach. Moreover, system emergencie s are defined***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 528 of 786

events and not declared by the owner/operator of specific combustion turbines, so there is limited opportunity for use of the provision. For these reasons, we are finalizing thatcommenters ’ fears that the exclusion will be subject to abuse are ove rstated. Therefore, electricity sold during hours of operation when thea unit is called upon to operate due to a system emer gency will not be counted toward the percentage electric sales threshold. The applicable emission standard during these perio ds would be the same standard that would otherwise apply (i.e., a heat input based standard for peaking and multi-fuel-fired uni ts and an output based standard for natural gas-fired base lo ad units). Electric sales fromHowever, electricity sold by units that are not called upon to operate specifically due to thea system emergency (e.g., units already operating when the s ystem emergency is declared) wouldwill be counted againsttoward the

total percentage electric 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 529 of 786 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 the applicability sectionSection IX.A.3.d , we are finalizing a version of the " broad applicability approach .". Under the broad applicability approach, the EPA solicited comment on a subcategorization approach b ased in part on natural gas-use. We received few comments on thi s approachissue . One of the comments we did receive was that

combustion turbines that burn fuels other than natu ral gas have higher CO 2 emissions due to the higher relative carbon conten t of alternate fuels. Besides hydrogen, 535 natural gas has the lowest

CO 2 emission rate on a lb/MMBtu basis of any fossil fu el. Therefore, burning fuels other than natural gas wil l result in a higher CO 2 emission rate. We interpret this comment to mean that, if we were to subcategorize based on fuel use , turbines

535 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 During Review *** Page 530 of 786 that burn non-natural gas fuels should receive a le ss 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. 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 included in thi s***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 531 of 786 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 Re duction 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. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 532 of 786 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. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 533 of 786

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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 534 of 786 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. 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 coal-***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 535 of 786 fired 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 536 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 537 of 786 represents the best balance of economic, environmen tal, and energy considerations." 536 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 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 Turbinesturbines 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 advance d NGCC technologies are the best system for reducing CO 2 emissions with

536 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir . 1981).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 538 of 786 no negative environmental impacts and no negative e conomic impacts on rate payers. They stated that advanced N GCC 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 Turbinescycle 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 539 of 786 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 strictly for base load operation. Some commenters also suggested that we should subca tegorize multi-fuel-fired combustion turbines, but did not p rovide any specific technologies that should be considered in the BSER analysis.

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 540 of 786

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

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 541 of 786 stops, similar to the operation of coal-fired boile rs. 537 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 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 steady-

537 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 During Review *** Page 542 of 786 state 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. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 543 of 786

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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 544 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 545 of 786 cycle technology when a unit’s electric sales excee d approximately one-third of its potential electric o utput. 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 546 of 786 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. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 547 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 548 of 786 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. 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 549 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 550 of 786 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

for non-base load units. Based on available EIA dat a, 538 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

.

538 http://www.eia.gov/electricity/data/eia923 //.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 551 of 786

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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 552 of 786 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

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 553 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 554 of 786 performance of existing NGCC units and takes into a ccount a range of operating conditions, future degradation, etc. Units not meeting either the percentage electric sales or natural gasuse criteria (i.e., non-base load natural gas-fired and multifuel units, respectively) will be subject to an inp ut-based

standard based on the use of clean fuels. This sect ion summarizes what emission standards we proposed and related issues we solicited comment on, describes the comme nts we received regarding the proposed emission standards and our responses to those comments, 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 gr eater than 850 MMBtu/h), we proposed an emission standard of 1 ,000 lb

CO 2 /MWh-g. For small stationary combustion turbines (b ase load rating of 850 MMBtu/h or less), we proposed an emis sion standard of 1,100 lb CO 2 /MWh-g. We also solicited comment on a range of 950 – 1,100 lb CO 2 /MWh -g for large stationary combustion turbines and a range of 1,000 – 1,200 lb CO 2 /MWh -g for small stationary

combustion turbines. In addition, we solicited comment on increasing the size distinction between large and small stationary comb ustion turbines to 900 MMBtu/h to account for larger aerod erivative***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 555 of 786 designs ; increasing the size distinction to 1,000 MMBtu/h t o

account for future incremental increases in base lo ad ratings; increasing the size distinction to between 1,300 to 1,800 MMBtu/h; and eliminating the size subcategories alt ogether. To account for potential reduced efficiencies when uni ts are not operating at base load, we also solicited comment o n whether a separate, less stringent standard should be establi shed for nonbase load combustion turbines.

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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 556 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 557 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 558 of 786 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 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-g and 1,200 lb

CO 2 /MWh-g for the newly constructed large and small tu rbines, respectively. They also advocated finalizing standa rds for modified and reconstructed standards that are 10 pe rcent higher***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 559 of 786

than the final standards for new sources because co mbustion turbines constructed prior to 2000 were not include d in the EPA's analysis. 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. These commenters stated that the appropriat e standard, consistent with Congressional objectives under CAA section 111,

should be 800 lb CO 2 /MWh-g based on the performance of the lowest

emitters in the CAMD database. Some commenters stat ed that a

standard of 850 lb CO 2 /MWh-g reflects BSER for high-capacity

factor units because half of the NGCC units in the CAMD database are achieving this level of emissions. One commente r from the power sector who operates NGCC power plants stated that the final standard for new large combustion turbines sh ould be 925

lb CO 2 /MWh-g. Another also commenter supported an emissio n standard of 925 lb CO 2 /MWh-g, which is consistent with recent

BACT determinations in the Statestate of New York. Several other

commenters stated that a reasonable standard for ne w large

combustion turbines should be 950 lb CO 2 /MWh-g and that the final

standard for new small combustion turbines should b e 1,000 lb

CO 2 /MWh-g. Numerous commenters stated that the final s tandards for new sources should not exceed 1,000 lb CO 2 /MWh-g for either large or small combustion turbines. Other commenter s stated***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 560 of 786 that, 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. b. Emission standards for non-base load natural gas -fired units

and multi-fuel-fired units Many commenters stated that the EPA cannot finalize “no emission standard” for non-base load units, which t he EPA solicited comment on in the broad applicability app roach. They argued that this approach was not consistent with t he definition of “standard of performance” in CAA section 111(a)( 1), which requires there to be an “emission limitation” that reflects a “system of emission reduction.” Some commenters rec ommended that non-base load units should be subject to work pract ice standards, such as operating safely with good air p ollution control practices, including CO 2 monitoring and reporting requirements. Other commenters pointed to recent PS D permits

that include tiered emission limits for the differe nt roles served by combustion turbines. They cited BACT limi ts from 1,328 to 1,450 lb CO 2 /MWh-g for peaking units. One commenter supported

tiered limits consistent with recent BACT determina tions in the

Statestate of New York, which include limits for simple cycle combustion turbines of 1,450 lb CO 2 /MWh-g. An air quality regulator from a state with rapidly increasing rene wable***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 561 of 786 generation supported a limit of 825 lb CO 2 /MWh-g for all base load NGCC units; 1,000 lb CO 2 /MWh-g for large intermediate load NGCC units; 1,100 lb CO 2 /MWh-g for small intermediately load NGCC

units. This commenter also recommended that the EPA set a numerical limit specifically for peaking units afte r the completion of a peaking unit-specific BSER analysis . Several commenters supported tiered standards based on capa city 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 (those operat ing 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 hour s 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. Since the standards were proposed, the EPA has expa nded the NGCC emission rate analysis that supported the prop osed emission***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 562 of 786

standards to include emissions information for NGCC units that commenced operation in 2011, 2012, and 2013, and up dated the emissions data to include emissions through 2014. I n our analysis, we evaluated 346 NGCC units with online d ates ranging from 2000 to 2013. The analysis included emissions data from

2007 to 2014 as submitted to the EPA’s CAMD. The av erage maximum 12-operating-month CO 2 emission rate for all NGCC units was 897 lb CO2/MWh-g, with individual unit 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 953 lb/MWh-g. Individual unit maximum emission r ates ranged from 898 to 1,175 lb CO 2 /MWh-g. Two of the units had a maximum emissions rate equal to or greater than 1,000 lb CO 2 /MWh-g. 539 However, one of the units with a maximum emission r ate above 1,000 lb CO 2 /MWh was only selling approximately 20 percent of i ts potential electric output (significantly below the designspecific percentage electric sales threshold) when the emission

539 For emission standards of 1,000 lb CO2/MWh-g and a bove, the emission standard uses three significant figures. See Section X.D.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 563 of 786 rate occurred. If this unit were a new unit, the ap plicable emission standard would be the heat input-based cle an fuels standard, and the unit would not be out of complian ce. Therefore, 16 of the 17 existing small NGCC units h ave demonstrated that an emission rate of 1,000 lb CO 2 /MWh-g is achievable. In addition, the six newest units, whic h commenced construction between 2007 and 2012, all have maximu m 12- operating-month emission rates of less than 950 lb CO 2 /MWh-g. While these units might not be old enough to have e xperienced degredation, their maximum emission rates demonstra te that the final standard of 1,000 lb CO 2 /MWh-g includes a significant compliance margin for any future degredation. For large units, the average maximum 12-operating-m onth

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. Twentythree of the 328 large NGCC units had maximum 12-op erating-month emission rates greater than 1,000 lb CO 2 /MWh. While we do not have precise design efficiency information for each of these units, and thus cannot calculate the precise percen tage electric sales threshold to which each unit would be subject , it appears that all of the emission rates in excess of 1,000 l b CO 2 /MWh-g occurred during periods when electric sales were lo w and would be below the threshold. Thus, if these units were n ew units, they would only have to comply with the heat input- based clean***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 564 of 786 fuels standard. Therefore, essentially all existing NGCC units would have been in compliance with the final emissi on standard.

We note also that there are 51 new NGCC units that have started operation since 2010, and the average maximum 12-op erating-month

emission rate for these units is 833 lb CO 2 /MWh-g. Therefore, the final emission standard includes a very significant compliance margin to account for any potential future degredat ion 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

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 degradationdegredation

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 565 of 786 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. While the non-base load natural gas-fired subcatego ry inherently addresses efficiency issues related to o perating conditionsFinally , the EPA evaluated the impact of run time per start, average duty cycle, and number of starts on emission

rates. While these factors do influence emission ra tes, even the majority of non-base load natural gas-fired non-base load NGCC could comply with the natural gas-fired base load e mission rate. Therefore,subcategory inherently addresses efficien cy issues

related to operating characteristics have been accounted for in

the final emission standardconditions

.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 566 of 786 In addition to evaluating existing NGCC emissions d ata, the

EPA reviewed the CO 2 emission limits included in preconstructionPSD preconstruction permits issued since January 1,

2011. AllWe evaluated all permit limits were evaluated over an annual 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 asin terms of lb/h or tons per year and were, so we did not includedinclude them in the analysis. In addition, one CHP unit that genera tes electricity and supplies steam to a chemical plant was in the

data set with a. 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, we did not include it was also not included 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 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-n. The lowest emission limit 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 /MWh-g. Of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 567 of 786 these 28 permit limits, the only permitted emission ratelimit in

excess of our final emission rate (i.e.,standard of 1,000 lb

CO 2 /MWh-g ) is for a relatively small NGCC unit (base load rating of 366 MMBtu/h) NGCC unit that commenced construction prior to

the EGU GHG proposal so isand thus 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 includeincludes all periods of operation (i.e.,, including startup, shutdown and malfunction ). events. In addition, alleach permit limits werelimit was set considering

theafter backup and additional fuel use . Specifically, were

taken into consideration. While some permits restrictedrestrict fuel use to only natural gas, while others allow limited the

available usage (duration and type) of backup and other fuel s. For example, the Pioneer Valley Energy Center has u nrestricted use of natural gas while restricting operation with, but can

burn ultra-low sulfur diesel (ULSD) for up to 1,440 hours per 12-month period. This permit required thatrequires the unit

continue to comply with a limit of 895 lb CO 2 /MWh-n even when burning up to 16 percent distillate oil. Each permi t limit also

consideredtakes into account the mode of operation for the

combustion turbine. In some casesFor example, the permit limit was determined to be appropriate because the combus tion turbine is intended to operate with frequently changing loa ds rather***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 568 of 786 than operating at relatively steady loads, and this mode of operation would make it difficult to meet lower lim its. For example,for the Lower Colorado River Authority's Ferguson plan t 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 unitunit’s expected operation at 50 percent gross load. For the combined cycle combustion turbineNGCC units

with duct burners on their HRSG, HRSGs, the permit limits

account for the hours of operation with duct burners was included in the determination of the permit limits. Typically, the hours of operation and heat input were limited to ensure that the units are operated in the most efficient w ay and reduce

their CO 2 emissions.firing. Finally, most offof these permits included an allowanceinclude compliance margins to account for efficiency losses due to degradation . The sum of these

allowances and other factors (e.g., degredation, actual operating parameters, site - specific design

considerationconsiderations , and the use of backup fuel ) was in the range of). In total, these compliance margins r esult in a 10 to 13 percent increase in the designpermitted CO 2 emission ratelimits, yet all of the limits except one were s till below 1,000 lb CO 2 /MWh-g

. In addition to the NGCC operating data and permit reviewFinally , we also reviewed NGCC design efficiency data and***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 569 of 786 specifications submitted to Gas Turbine World. Spec ifically, we review the reported efficiency data for 88 different 60 Hz combined cycleNGCC units frommanufactured by Alstom, GE Energy Aeroderivative and Heavy Duty, Mitsubishi Heavy Ind ustries, Pratt & Whitney, Rolls-Royce, and Siemens Energy. T he reported designs ranged in model year from 1977 to 2011, cap acities ranged from 31 to 1,026 MW, and base load ratings r anged from 236 to 3,551 MMBtu/h. The average reported design e mission rate

for these units iswas 834 lb CO 2 /MWh-n and ranged from 725 to 941

lb CO 2 /MWh-n. The corresponding compliance margin relative to the Therefore, our optional standard of 1,030 lb CO 2 /MWh-n averaged would allow for an average compliance margin of 24 percent and ranged , with a range from 10 to 42 percent ., over the design

rate. Ninety-five percent of these designs would have a compliance margin of 13 percent or more . This is, the top end of the range of allowancecompliance margins determined to be appropriate in the GHGPSD permits we reviewed . Therefore, these designs would likely be able to comply with an emis sion rate of 1,000 lb CO 2 /MWh-g

. SinceBecause some commenters expressed concern about the achievability ofwere concerned that smaller NGCC un its will not

be able to achieve the emission standard for smaller NGCC units , we specifically considered the design rates for sma ller units. For the 52 small units (base load rating of 850 MMB tu/h or***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 570 of 786 less), the average design emission rate iswas 865 lb CO 2 /MWh and ranged from 796 to 941 lb CO 2 /MWh-n. The correspondingTherefore, our optional standard of 1,030 lb CO 2 /MWh-n would allow for an

average compliance margin averaged 19 percent and ranged from , with a range of 10 to 29 percent ., over the design rate. Ninetyfive percent of small NGCC designs would have a compliance margin of 13 percent or greater. Therefore, the vast majority of currently available small NGCC designs would also l ikely be able to comply with an emission rate of 1,000 lb CO 2 /MWh-gmore

. We further refined our analysis by only considering the

most efficient NGCC design for a given combustion turbine engine. For example, GE Energy Aeroderivative offer s four NGCC design options for theirits LM2500 model-type , all with a rating of approximately 45 MW. The design emission raterates for these various options range from 827 to 914 lb CO 2 /MWh-n. When only the

most efficient NGCC models are considered for a particular combustion turbine engine design are considered , all the NGCC models have over a 13 percent compliance margin. DevelopersIn other words, developers of new base load natural gas-fired

combustion turbines concerned about the achievabili ty of the final standard have multiple more efficient option evenoptions offered by the same manufacturer. Therefore, we hav e concluded

that the final requirements of this rulemakingemission standard***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 571 of 786 allows sufficient flexibility for end users to sele ct an NGCC design appropriate for their specific requirements. After considering these three sources of informatio n - actual NGCC emission rate data, NGCC GHGPSD permit requirementslimits for NGCC facilities , and NGCC design

information – we have concluded that a standard of 1,000 lb

CO 2 /MWh is both achievable and appropriate for new and reconstructednewly constructed base load natural gas-fired combustion turbines. While we anticipate that the large majority of new NGCC units will operate well below this emis sion rate, this standard provides flexibility considering site for developers to take into account site- specific conditions (e.g., ambient conditions and cooling system), operating characteristics (e.g., part-load operation and freq uent starting and stopping), and reduced efficiency due to degredation , and.

The standard also accommodates the full size range of turbines. In addition, we

We also expect multiple technology developments to further increase the performance of new base load natural g as-fired stationary combustion turbines. First, vendorsVendors continue to improve the single cycle efficiency of combustio n turbines. The use of more efficient combustion turbine engine s improves the overall efficiency of combined cycleNGCC facilities. In addition, existing smaller combined cycleNGCC facilities were***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 572 of 786 likely designed using single or dual pressure heat recovery steam generatorsHRSGs without a reheat cycle. New designs

couldcan incorporate three pressure steam generators with a reheat cycle to improve the overall efficiency of t he combined cycleNGCC facility. Finally, additional technologies to redu ce emission rates for new combustion turbines include CHP and integrated non-emitting technologies. For example, an NGCC unit that is designed as a CHP unit where ten percent of the overall output is useful thermal output would have an emiss ion rate approximately five percent less than an electric on ly NGCC . In sum, we believe that our final emission standards o f 1,000 lb

CO 2 /MWh-g and 1,030 lb 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 573 of 786 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 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 for cooling the 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 574 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 575 of 786 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. 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 540,541,542 , 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

540 "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. 541 "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. 542 "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 During Review *** Page 576 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 577 of 786 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 WeThe EPA agrees with the commenters who stated tha t “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 , as opposed to an output-based standard, for non-base load natural gas-fired combustion turbines in recognition that efficiency can be reduced due to operation at low loads, cycling, and frequent startups. The EPA has concluded that, at this time, we do not have sufficient information to set a meaningful out put-based standard for non-base load natural gas-fired combus tion turbines. The input-based standard requires non-bas e load units to burn fuels with an average emission rate of 120 lb CO 2 /MMBtu or less. This standard is readily achievable becaus e the CO 2 emission rate of natural gas is 117 lb CO 2 /MMBtu. The most common backup fuel is distillate oil, which has a CO 2 emission rate of

163 lb CO 2 /MMBtu. A non-base load natural gas-fired combustio n turbine burning 9 percent distillate oil and 91 per cent 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 operators of natural gas-fir ed non-base***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 578 of 786

load combustion turbines will be able to achieve th e 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 , ethane , ethylene, propane, naphtha, jet fuel kerosene, dist illate oils 1 and 2, and biodiesel) will only need to maintain re cords that 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 perating - month compliance period . Owners and operators of these units

will have to and submit quarterly reports to verify that they are in compliance with the required emission standard. d. Newly constructed and reconstructed multi-fuel-f ired units

We also are finalizing an input-based standard based on th e use of clean fuels, as opposed to an output-based s tandard, for

multi-fuel units for multipleseveral reasons. These reasons***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 579 of 786 includeSpecifically, we do not currently have continuous CO 2 emissions data for multi-fuel -fired units, we have not evaluated the potential efficiency impacts of different fuels , and the range of carbon content of non-natural gas fuels co mplicates establishing an appropriate output - based standard. Based on

thethis lack of these data, we have concluded that we cannot establish an output - based emission standard for multi-fuel

fired combustion turbines at this time. The input-based emissions standard established for this subcategory is based on the use of clean fuels. The use of clean

fuels will ensure that newnewly constructed and reconstructed

combustion turbines minimize CO 2 emissions during all periods of operation by limiting the use of fuels with higher CO 2 emission rates. To accurately represent the BSER and limit t he ability of

units to co-fire higher CO 2 emitting fuels with natural gas and still be in compliance with the emission standard , 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 specific 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 specific standard

will be calculatingcalculated by adding the product of the percent of heat input from natural gas and 120 with the product of the heat input from non-natural gas fuels and 16 0. For***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 580 of 786 example, a combustion turbine that burns 80 percent natural gas and 20 percent fueldistillate oil would be subject to an

emission standard of 130 lb CO 2 /MMBtu (rounded to two significant figures ). This standard is readily achievable since distil late oil is the clean fuel with the highest CO 2 emission rate and the

actual emission rate of this unit is also 130 lb CO 2 /MMBtu (rounded to 2 significant figures). ), which is equ ivalent to the actual emission rate of a unit burning this com bination of fuels. On the other hand, a combustion turbine that burns 100 percent residual oil would be subject to an emissio n standard 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, t he standard will restrict higher carbon fuels from being burned in multifuel-fired units, but will be readily achievable by units burning clean fuels. According to information submitted to the EIA, the primary, non-natural gas fuels used by combustion turbines today for the production of electricity should all meet our definition of a

clean fuel. ConsistentThus, while the approach finalized for non-base load natural gas-fired units,emission redu ctions that will result from restricting the use of fuels with higher CO 2 emission rates is minor, the compliance burden is a lso minimal. Owners and operators of multi-fuel units-fired combustion

turbines burning only commonly used fuels with a consistent***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 581 of 786

chemical compositioncompositions 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 of the fuel(s)that they burned during the applicable 12-operating month periods. Burning only these

fuels in the combustion turbine. No additional recordkeeping or reporting will be required. Therefore, the requirements for multi-fuel unit will not result in significant emis sion reductions and the compliance costs will be minimal 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

. Owners and operators of multi-fuel units burning fu els with higher CO 2 emission rates and/or chemical compositions that v ary will have to follow the procedures in part 98 of th is part to determine the average CO 2 emission rate of the fuels burned during the applicable 12-operating month compliance period. Owners and operators of these units must operate an d calibrate all flow meters, composition analyzers and pressure gauges used for measuring compliance parameters according to th e procedures***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 582 of 786 in §98.3(i) and submit quarterly reports to verify that they are in compliance with 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 notedexplained in sectionSection XV below, we are withdrawing the June 2014 proposal with respect to these source s. We received a significant number of comments asserting that modified combustion turbines could not meet the pro posed emission standards of 1,000 lb/MWh-g for large turb ines and 1,100 lb/MWh-g for small turbines. For the reasons explained in Section IX.B.1 above, we have decided not to subcat egorize

combustion turbines based on size for a number of r easons and are setting a single standard of 1,000 lb/MWh-g for all base load natural gas-fired turbines instead. While we a re confident

that all new and reconstructed units will be able t o achieve this standard, we are less confident that all smaller combustion

turbines that undertake a modification , specifically those that were constructed prior to 2000, will be able to do so. Until we have the opportunity to further investigate the ful l range 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 583 of 786 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 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 ann ual emissions increase would be relatively minor because operatin g permits generally limit the amount of distillate oil that a unit can burn. We need to conduct additional analysis to det ermine an appropriate emission standard for units that undert ake this type of modification, which does not involve any of the combustion turbine components that impact efficiency.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 584 of 786 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 the proposed standards for all combustion turbines that conduct modifications and is not issuing final standards fo r those

sources at this time. See sectionSection XV below. We note that

the effect of this withdrawal is that modified comb ustion turbines will continue to be existing sources subje ct to section 111(d). 543

543 As discussed above in Section VI.A

. of this preamble, 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 During Review *** Page 585 of 786 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. A. Startup, Shutdown, and Malfunction Requirements

In its 2008 decision in Sierra Club v. EPA , 551 F.3d 1019 (D.C. Cir. 2008), the D.C. Circuit vacated portions of two provisions in the EPA’s CAA section 112 regulations governing the emissions of hazardous air pollutants (HAP) dur ing periods of startup, shutdown, and malfunction (SSM). Specif ically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that under section 3 02(k) of the CAA, emissions standards or limitations must be con tinuous in nature and that the SSM exemption violates the CAA' s requirement that some CAA section 112 standards apply continuou sly.

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 586 of 786 startup and shutdown periods and, for the reasons e xplained below as well as in Section V.J.1 above, has not es tablished alternate standards for those periods. Specifically , startup and shutdown periods are included in the compliance cal culation as periods of partial load. The final method to calcul ate 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 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. As 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 587 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 588 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 589 of 786 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

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 590 of 786

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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 591 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 592 of 786 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 courts, not EPA.”). 544 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

544 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 593 of 786 arises). The same is true for the presiding officer in EPA

administrative enforcement actions. 545 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 for the majority of the CO 2 and energy output monitoring requirements while ensuring accur acy 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).

545 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 During Review *** Page 594 of 786 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 appendix D of part 75. 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 40 CFR 75.53(g) and (h). The electronic portion of the monitoring plan should be submitted to the EPA’s CAMD using the Emissions Collection and M onitoring Plan System (ECMPS) Client Tool. The hard copy port ion of the plan should be sent to the applicable Statestate and EPA Regional office. Further, all monitoring systems us ed to

determine the CO 2 mass emission rates have to be certified according to 40 CFR 75.20 and section 6 of part 75, appendix A***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 595 of 786 within the 180-day window of time allotted under 40 CFR 75.4(b), and are required to meet the applicable on-going qu ality assurance procedures in appendices B and D of part 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 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, part 75 bias adjustment factors (BAFs) should not be app lied to the flow rate data. These restrictions on the use of pa rt 75 data for part 60 compliance are consistent with previous NSPS regulations and revisions. Additionally if an affec ted EGU combusts natural gas and/or fuel oil and the CO 2 mass emissions***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 596 of 786 rate are measured using Equation G-4 in appendix G of part 75, then determination of site-specific carbon-based F- factors using Equation F-7b in section 3.3.6 of appendix F of par t 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. 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 40 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 597 of 786

• 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 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 40 CFR 75.10(e) and 75.20(d ), to help meet this data capture requirement. This requiremen t is separate from the requirement for a source to demonstrate co mpliance with an applicable emission standard. When demonstrating compliance

with an emission standard the calculation must use all valid data to calculate a compliance average even if the percent of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 598 of 786 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 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 40 CFR 75.64(a), the final rule requires an EGU owner or operator to begin reporting emissio ns data when monitoring system certification is completed or whe n the 180-day window in 40 CFR 75.4(b) allotted for initial certi fication of the monitoring systems expires (whichever date is e arlier). For EGUs subject to the 1,400 lb CO 2 /MWh-g) emission standard, the initial performance test consists of the first 12 o perating months of data, starting with the month in which em issions are first required to be reported. The initial 12-opera ting-month compliance period begins with the first month of th e first calendar year of EGU operation in which the facilit y exceeds the capacity factor applicability threshold. The traditional 3-run performance tests (i.e., stac k tests) described in 40 CFR 60.8 are not required for this rule.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 599 of 786 Following the initial compliance determination, the emission standard is met on a 12-operating-month rolling ave rage basis. D. Continuous Compliance Requirements Commenters 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 t hat compliance with the 1,400 lb CO 2 /MWh-g emission limit is 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 40 CFR 75.64(a), i.e., either the month in which mo nitoring system certification is completed or the month in w hich the 180- day window allotted to finish certification 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 600 of 786 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 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 2two 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 suggested 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 601 of 786

emission limit." The final rule requires that the 12-operating - month rolling average emission rate must be rounded to 3three significant figures if the applicable emissions sta ndard is greater than or equal to 1,000 (e.g., an actual emi ssion 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 t he actual

emission rate to 2two significant figures (e.g., an actual emission rate of 454.9 kg CO 2 /MWh is rounded to 450 kg CO 2 /MWh). Historically, many of the emissions limits under pa rt 60 have been expressed to 2two significant digits (e.g., the original SO 2 emission standard for coal-fired units under Subpar t D was 1.2

lb SO 2 /MMBtu). The rounding conventions under the General Provisions allow the reporting of all emission rate s in the range from 1.15 to 1.249 as 1.2 lb SO 2 /MMBtu. During compliance periods with emissions at the lower end of this ran ge, the operator is required to report higher emissions tha n actually occurred; during compliance periods at the upper en d of this range the operator is allowed to report lower emiss ions than actually occurred. In either case the absolute erro r remains small because the emission rate in this example is a relatively small numerical value. In addition, the required em ission reductions typically are large enough that rounding does not impact the emission control strategy of affected un its. However,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 602 of 786

the final standards for CO 2 emissions include numerical values that are larger than many historical emissions stan dards and require a relatively small percent reduction in emi ssions. Accordingly, it is appropriate to require the use o f three significant digits when completing compliance calcu lations resulting in numerical values larger than 1,000. Th is is particularly important when considering the relativ ely small emission rate changes that may be required for comp liance with the unit-specific emission standards being finalize d for modified steam generating and IGCC units because a rounding error of 5 percent may be larger than the percent d ifference between the affected unit's historically best emiss ion rate and the emission rate immediately preceding the modific ation. 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 Commenters supported the coordination of notificati on, recordkeeping, and reporting required under this ru le in conjunction with the requirements already in place under part 75 and, so the EPA has made the requirements as efficient and streamlined as possible with the current requiremen ts under part 75. The final rule requires an EGU owner or operato r to comply***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 603 of 786 with the applicable notification requirements in 40 CFR 75.61, 40 CFR 60.7(a)(1) and (a)(3), and 40 CFR 60.19. The rule also requires the applicable recordkeeping 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 moist ure content (if needed), unit operating time, and gross electri c generation. For EGUs that exclusively combust liquid and/or gas eous fuel(s)

and elect to determine CO 2 emissions using Equation G-4 in appendix G of part 75, the key data elements in sub part F that are recorded include hourly fuel flow rates, fuel u sage times, fuel GCV, gross electric generation. 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 part 75, appen dix 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 604 of 786

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 part 75. The reports in appendix G tha t do not include data required to calculate compliance with the applicable CO 2 emission standard are not required to be reported under this rule. The rule requires the reports in 4 0 CFR 60.5555 to be submitted using the ECMPS Client Tool. Except for a few EGUs that may be exempt from the Acid Rain Program (e.g., oilfired units), this is not a new reporting requireme nt. Sources subject to the Acid Rain Program are already requir ed 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 part 75 reporting requireme nts. The first report is for the quarter that includes the f inal (12 th )***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 605 of 786 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

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 40 CFR 60.5555(a)(2) for affected EGUs. However, we wi ll make the necessary modifications to the system in order to f ully***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 606 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 607 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 608 of 786 legislative history. 546 See Section III.H.3.b.4 above. For instance, the 1970 Senate Committee Report explains that “[t]he 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.” 547 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. 548,549

546 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). 547 Sen. Rep. No. 91-1196 at 15-16, 1970 CAA Legis. Hi st. at 416 (emphasis added). 548 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 Statesstates and appropriate air pollution control 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”). 549 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 609 of 786 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, 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, 550 and in this case

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). 550 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 During Review *** Page 610 of 786 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). 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 for the following reasons: Newbecause new steam units would have a significantly limited range of options to im plement building blocks 2 and 3. The new source performance standard was proposed an d is being finalized as a rate-based standard. Thus, if building blocks 2 and 3 were included in the BSER, a more st ringent ratebased standard would be applicable to all new sourc es. However, it is conceivable that the EPA could propose a hybr id standard

that would include both an emission-rate limit that reflects partial CCS and a requirement for allowances that r eflects building blocks 2 and 3. Accordingly, the following discussion***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 611 of 786 assumes either a rate-based or mass-based standard, or part of a hybrid standard. 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 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 the 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 612 of 786

and 3 , and can adjust investment obligations among themse lves 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 sou rces being able to trade with existing sources, for seve ral reasons. First, as noted, there are indications in the legis lative history that new sources should be well-controlled at the source, which casts doubt on whether new sources sh ould be allowed to meet their standards through the purchas e of emission

credits. Second, new sources must meet their standards of performance as soon as they begin operations. If th ey do so before the year 2022, when existing sources become subject to section 111(d) state plan standards of performance, no existing sources will be available as trading partners. 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 that new sources would not have the advantage of this lead t ime were they***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 613 of 786 subject to more stringent standards that also reflected in the building blocks. 551 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 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. 552

B. New Combustion Turbines For new combustion turbines, the building blocks ar e not appropriate as part of the BSER for the following

reasons:either. Building block 1 is limited to steam generating units, and therefore has no applicability to new co mbustion

551 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. 552 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 During Review *** Page 614 of 786 turbines. Measures comparable to those in building block 1 would not be appropriate because thenew highly efficient NGCC construction already entails high efficiency equipm ent and operation. Building block 2 is also limited to steam generatin g units and is not appropriate as part of the BSER for new NGCC units because it would not result in any emission reducti ons. 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 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 below its limit as a safety margin. This represents a substantial c ommitment of***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 615 of 786 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 modified

or reconstructed NGCC units – the BSER for them, too, is already based on highly efficient performance. Building block 2 is not appropriate for modified or reconstructed NGCC units because it would not yield any reductions. Building blocks 2 and 3 are not appropriate for mod ified or reconstructed steam generators, and building block 3 is not appropriate for modified or reconstructed NGCC units, for the same reasons that they are not appropriate for new EGUs, as described above (limited range of options for imple mentation (including lack of availability of trading), lack o f lead-time for implementation, and the possibility of reducing the availability of renewable energy for existing sourc es). 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 616 of 786 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)BACT requirement for GHGs continues to apply after promulgation of this rule. This rule does not require any additional revisions to S tate Implementation Plans. As discussed further below, t his 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 perm its program, this rule does not affect whether sources are subje ct 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 does ha ve 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 617 of 786 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 these part 60 provisions. The Supreme Court has sin ce clarified that the PSD program does not apply to smaller sour ces based on the amount of GHGs they emit. However, because the largest sources emitting GHGs remain subject to the PSD per mitting requirements, the EPA has concluded that it remains appropriate to adopt the proposed regulatory provisions in 40 C FR part 60 in

this rule. We discuss our reasons for this action i n 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 618 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 619 of 786 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” 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 620 of 786 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 GHGs would not be subject to PSD requirements unless the sourc e emitted GHGs in the amount of 75,000 tons per 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” unle ss the source

emits GHGs at or above this threshold. The Tailorin g Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These provisions contain threshol ds that, when applied through the definition of “regulated NSR po llutant,” function to limit the scope of the terms “major sta tionary source” and “major modification” that determine whe ther a source is required to obtain a PSD permit. See e.g. 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 51.166(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 1487-1488. As discussed above, the defin ition of “regulated NSR pollutant” in the PSD regulations co ntains a separate PSD trigger for air pollutants regulated u nder the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 621 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 622 of 786 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 1488 (citing 75 FR 315 82). Nevertheless, to ensure there would be no uncertain ty as to this issue, the EPA proposed to adopt explicit language in 40 CFR 60.46Da(j), 40 CFR 60.4315(b), and 40 CFR 60.5515 o f the agency’s regulations. The proposed language makes c lear 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 this rule. 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 CO 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 623 of 786 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

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 40 CFR 51.166( b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA’s regulations, bu t did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR 52.21(b)( 48)(iv). The court also directed the EPA to consider whether any further revisions to its regulations are appropriate in lig ht of UARG v.

EPA , and, if so, to undertake such revisions.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 624 of 786 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 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 40 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 625 of 786 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.

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 40 CFR 60.5515 (subpart TTTT). Because the EPA is not finalizing the proposed regulations in s ubparts Da and KKKK, it is not necessary to adopt the comparab le provisions that the EPA proposed in 40 CFR 60.46Da(j) and 40 C FR 60.4315(b) The EPA has evaluated 40 CFR 60.5515 in light of th e Supreme Court decision and the comments received on the question

of whether this CAA section 111 standard will under mine the***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 626 of 786 application of the Tailoring Rule limitations. Whil e most of the Tailoring Rule limitations are no longer needed to avoid triggering the requirement to obtain a PSD permit b ased on GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv) a nd 40 CFR 52.21(b)(49)(iv) will remain important to provide a n interim applicability level for the GHG BACT requirement in “anyway source” PSD permits. Thus, there continues to be a need to ensure that the regulation of GHGs under CAA sectio n 111 does not make this BACT applicability level for anyway s ources effectively inoperable. The language in 40 CFR 60.5 515 will continue to be effective at avoiding this result af ter the judicial actions described above and the adoption o f this final rule. The provisions in part 60 reference 40 CFR 51 .166(b)(48) and 40 CFR 52.21(b)(49) of the EPA’s regulations. H owever, the courts have now vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v), and the EPA will take steps soon t o eliminate these subparts from the CFR. As a result of these s teps, the language of final 40 CFR 60.5515 will not incorpora te the vacated parts of 40 CFR 51.166(b)(48) and 40 CFR 52 .21(b)(49), but these provisions in part 60 will continue to ap ply to those subparts of the PSD rules that are needed on an int erim basis to limit application of BACT to GHGs only when emitted by an anyway source in amounts of 75,000 tpy CO 2 e or more. Thus, in this final***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 627 of 786 rule, the EPA is adopting the proposed text of 40 C FR 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 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,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 628 of 786 the EPA will need to consider adding provisions lik e 40 CFR 60.5515 to other subparts of part 60. In a separate rulemaking finalized concurrently with this rule, the EPA is a lso finalizing corresponding edits to 40 CFR 60.5705 in Subpart UUUU to clarify that the regulated pollutant is the same for both the CAA section 111(b) and section 111(d) rules. As of this time, the EPA has not proposed GHG standards for other so urce categories under CAA section 111. To the extent nee ded, this approach of adding provisions to a few subparts in part 60 would

be less burdensome to states and more efficient tha n revising 40 CFR 51.166 at this time solely to address the impli cations of regulating GHGs under CAA section 111. The EPA understands that many commenters expressed concern

that PSD SIPs would also have to be amended to addr ess the implications of regulating GHGs under CAA section 1 11. However, the language in 40 CFR 60.5515 is designed to avoid the need for states to make revisions to the PSD regulations in their SIPs at this time. The EPA has previously observed that the form of each pollutant regulated under the PSD program is derive d from the form of the pollutant described in regulations, suc h 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

31522.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 629 of 786 Moreover, it is more likely that states would need to

consider a SIP revision if the EPA were to revise 4 0 CFR 51.166 in this rule. Revisions to 51.166 can trigger requi rements for states to revise their PSD program provisions under 40 CFR 51.166(a)(6). 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 consolida te 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 630 of 786 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 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 for purposes of ens uring 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 5 2 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 631 of 786 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 , 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 632 of 786 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

. 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

a 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 633 of 786

reconstructed sourcesunits, as those terms are defined in this

rule and under part 60. It is importantConsequently, this NSPS could establish a BACT floor for existing stationar y sources that are modifying an existing EGU and experience a n emissions increase that makes the source subject to recognize thatPSD review. However, a physical change that triggers the NSPS modification or reconstruction requirements does no t necessarily subject the source to PSD requirements, and vice ve rsa. In general, in order to trigger the NSPS modification or reconstruction requirements, a physical change must increase the maximum hourly emission rate of the pollutant (to b e an NSPS modification) or the fixed capital cost of the chan ge must exceed 50 percent of the fixed capital cost of a co mparable 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,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 634 of 786 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 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 EGU or non-E GU source. As noted above, BACT is a case-specific review by a pe rmitting agency. In evaluating BACT, the permitting authorit y should consider all available control technologies that ha ve the potential for practical application to the facility or emission

unit under evaluation. 553 This See GHG Permitting Guidance at 24.

This BACT review must include any technologies that are part of an applicable NSPS for the specific type of source and would therefore establish the minimum level of stringency for the

BACT. Thus, it is possible that partial CCS could be con sidered in a BACT review as an available control option for a modified

553 U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 24 (March 2011).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 635 of 786 or reconstructed EGU facility, or for another type of source (e.g., natural gas processing plant), but this NSPS is not an applicable standard to such sources so it would not establish a requirement that partial CCS is a minimum level of stringency

for the 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 the legal consequence of setting an NSPS u nder the

terms of the CAA. WeConsequently, we respond to these comments in other sections of this preamble that support the selection of partial CCS as the basis for the BSER for fossil fu el-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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 636 of 786 analysis and that technological capabilities and co sts evolve

over time. 554 In addition, to date the EPA has not issued a PSD

554 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 available technically feasible at modified sources , (citing possible issues with “space for CO 2 capture equipment at an existing facility”), or in other specific circumstances. Id. at 36 (“ While CCS is a promising technology, EPA does not believe that a t this time CCS will be a technically feasible BACT option in certain cases.... The EPA recognizes the significant logistical hurdles that the installation and operat ion of a CCS system presents and that sets it apart from oth er add-on control that are typically used ... Logistical hurdles for CCS may include obtaining contracts for offsite land ac quisition ..., the need for funding..., timing of available trans portation infrastructure, and developing a site for secure lo ng term storage. Not every source has the resources to over come the offsite logistical barriers necessary to apply CCS technology to its operations, and smaller sources w ill likely be more constrained in this regard ”); id”). Id . at 42-3 (notingEPA also noted that CCS may be expensive in individual instances and thus eliminated as a contr ol option for that reason under step 4 of the BACT analysis, noting further that revenues from EOR may offset other cos ts ).. Id. at 42-3. See also UARG v. EPA , 134 S.Ct. 2427, 2448 (2014) (noting that EPA’s GHG Permitting Guidance states t hat carbon capture is reasonably comparable to more tra ditional, end-of-stack BACT technologies, and that petitioner s 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 637 of 786 permit with GHG BACT for a source that would be an affected 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 GHGs in January 2011 and more information about GHG cont rol technology has been gained in this four-and-a-half year period. Thus, we would expect BACT decisions to evolve as w ell, 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

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 determined in this rule that partial CCS is the best system of emission reductionBSER , and the concerns voicedexpressed in the Guidance thus must be considered in that broader co ntext.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 638 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 639 of 786

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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 640 of 786 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 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 i dentified "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 all cont rol options with potential application to the emissions unit un der review.” GHG Permitting Guidance at 26. The EPA agrees that the GHG Permitting Guidance only uses the term “CCS” and do es 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 641 of 786 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. 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 1489-9 0. 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 642 of 786

definitions in the titleTitle V regulations of “major source” and “subject to regulation.” 79 FR 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 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

1489-90.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 643 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 644 of 786 requirements for GHGs will not result in the EPA imposing a requirement that stationary sources obtain a titleTitle V permit solely because such sources emit or have the potent ial to emit GHGs above the applicable major source thresholds. 555 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. 556 Consistent with the proposal, the EPA has conclude d

555 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.

556 See Memorandum from Janet G. McCabe, Acting Assist ant Administrator, Office of Air and Radiation, and Cyn thia Giles,***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 645 of 786 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 par t of 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

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 During Review *** Page 646 of 786 for GHGs, then approved part 70 programs implemente d by state, local and tribal permitting authorities 557 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 79 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 . 79 FR 1490. The EPA did not propose any action related to state and local p ermitting authorities that do not use the presumptive minimum approach.

557 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 During Review *** Page 647 of 786 Most commenters on the proposal, including state a nd local permitting authorities, were supportive of exemptin g GHGs from 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 648 of 786 Administrator may determine adequately reflects the reasonable costs of the permit program.” See also 40 CFR 70.9( b)(2). This 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 649 of 786 minimum calculation for all non-GHG fee pollutants (“the GHG adjustment option 2”). The EPA also solicited comme nt on an 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 79 FR 149 3-1495. 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. 79 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 650 of 786 calculation)” in 40 CFR 71.2. 558 See NSPS preamble 79 FR 1493,

1495. 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, 559 “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 1494.

558 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 pollutant” which includes air pollutants “subject t o any standard promulgated under section 111 of the Act.” 559 Burden is the hours of staff time necessary to per form a task.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 651 of 786 For part 71, we proposed a labor rate assumption of $52 per hour in 2011 dollars. Using that labor rate, we pro posed to determine the GHG fee adjustment for each GHG permi tting program activity to be a specific dollar amount for each ac tivity (“set fees”) that the source would pay for each activity performed. See 79 FR 1495. The EPA proposed to revise 40 CFR 7 0.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this option. c. The GHG adjustment option 2 The second proposed GHG adjustment option (option 2 ) was to increase the dollar per ton ($/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. 560 See NSPS proposal 79 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,

560 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 During Review *** Page 652 of 786 the cost of permitting for any particular source ma y be accounted for adequately without charging any addit ional fees

related to GHGs. Id. 79 FR 1494-1495. 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), 561 rather than solely CO 2, which would be regulated under the section 111 standards and implemented through the EGU GHG NSPS. Id . 79 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. 79 FR 1490, 1517, 1518.

561 Note that in 40 CFR §70.2 and §71.2, the term “Gre enhouse gases (GHGs)” is defined as the “aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, me thane, hydrofluorocarbons, perfluorocarbons, and sulfur he xafluoride.”***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 653 of 786 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

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 654 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 655 of 786 programs, and we are taking those comments into con sideration in the finalization of the rulemaking action. a. The GHG 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 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 656 of 786 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 562 if the state is barred from exceeding minimum requirements set by the EPA. Despite this a dverse 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).

562 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 During Review *** Page 657 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 658 of 786 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. 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

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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 659 of 786 States that implement the presumptive minimum appr oach will need to follow the final rule’s option 1 approach. 563 States that use the detailed accounting approach are not direct ly affected by this rulemaking, but they must ensure that their fee 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

563 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 During Review *** Page 660 of 786 assessment of the significance of the changes. Cert ain changes, such as switching from the presumptive minimum meth od to a detailed accounting method, will be considered subs tantial program revisions and be subject to the requirement s 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 CFR 71.9(c)(1)-(4) 564 , 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.

564 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 from the EPA (see §71.9(c)(2)); the EPA with contractor assistance (s ee §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 During Review *** Page 661 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 662 of 786 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.” 565 The EPA had proposed 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.

565 The EPA notes that the term “permit modification” in this context refers to all significant permit modifications and minor 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 During Review *** Page 663 of 786 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

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. 566 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

566 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 During Review *** Page 664 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 665 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 666 of 786 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 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. 567 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

567 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 During Review *** Page 667 of 786 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 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 te xt within 40 CFR part 60, subpart TTTT, to clarify that the f ee pollutant***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 668 of 786 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 part 60, subparts Da , KKKK and

TTTT. The final rule adds the clarification text on ly to subpart TTTT because the EPA is codifying all of the requir ements for the affected EGUs in a new subpart TTTT and includi ng all CO 2 emission standards for the affected EGUs (electric utility steam generating units, as well as natural gas-fired stat ionary combustion turbines) in that newly created 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 669 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 670 of 786

rules. 568 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 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

568 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 During Review *** Page 671 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 672 of 786 to an additional year, if it is needed to ensure el ectricity reliability. 569 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 , and May 1, 2017, for ozone season NO X . Many of the power plants participating in CSAPR have taken actions to reduce hazardous

569 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 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 During Review *** Page 673 of 786 air pollutants for MATS compliance that will also r educe SO 2 and/or 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 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. 570 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

570 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 During Review *** Page 674 of 786 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 Sec tion IX.C of the preamble to the CAA section 111(d) emission gui delines for existing EGUs that the EPA is finalizing simultaneo usly with this rule. Although the recently issued 316(b) rule discussed here applies to existing sources, there are also 31 6(b) technology-based standards for new sources with coo ling 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 675 of 786 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 Section IX.C of the preamble to the CAA section 111 (d) emission guidelines for existing EGUs that the EPA is finali zing along

with this rule.

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 676 of 786 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 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 fos sil fuelfired steam generating units that can be met by cap turing and storing approximately 16 to 23 percent of the CO 2 produced from the facility or by utilizing other technologies suc h as natural***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 677 of 786 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, 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 678 of 786 ensuring that all applicable environmental requirem ents are

met. 571 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 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. XIII. Impacts of this Action As explained in the “Regulatory Impact Analysis for the

Standards of Performance for Greenhouse Gas Emissio ns for New,

571 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 During Review *** Page 679 of 786 Modified, and Reconstructed Stationary Sources: Ele ctric Utility Generating Units” (EPA-452/R-15-005, August 2015) ( RIA), available data indicate that, even in the absence o f 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 on owners and operators of newly constructed EGUs b y 2022. 572 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 that s how 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.

572 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 680 of 786 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 Impactsair 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 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 EGUs to trigger the NSPS modification or reconstruc tion 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., ammonia, NH 3 ) from the capture process. To reduce the amine emissions, MHI introduced the first optimized washi ng system***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 681 of 786 within an absorber column in 1994, and developed a proprietary washing system in 2003. In that system, a proprieta ry reagent is added to the water washing section to capture amine impurities such as amine, degraded amine, ammonia, formaldehyd e, acetaldehyde, carbonic acids and nitrosamines. 573 MHI has continued to improve this technology for further re duction of

amine emissions and established an “advanced amine emission reduction system”. 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. 574

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. 575,576 Additional research continues in this area.

573 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). 574 Kamijo, T.; et al., “SO 3 Impact on Amine Emission and Emission Reduction Technology”, Energy Procedia , Volume 37, 1793 (2013). 575 Sharma, S. (2014). 576 Mertens, J.; et al., “Understanding ethanolamine ( MEA) and ammonia emissions from amine based post combustion carbon***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 682 of 786 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 Services) is required by the ESA. Section 7(a)(2) o f the ESA requires federal agencies, in consultation with the Service(s), to ensure that actions they authorize, fund, or car ry out are not likely to jeopardize the continued existence of federally listed endangered or threatened species or result i n the destruction or adverse modification of designated c ritical habitat of such species. 16 U.S.C. 1536(a)(2). Unde r relevant implementing regulations, ESA section 7(a)(2) appli es only to actions where there is discretionary federal involv ement or control. 50 CFR 402.03. Further, under the regulati ons consultation is required only for actions that “may affect” listed species or designated critical habitat. 50 C FR 402.14. Consultation is not required where the action has n o effect on

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 During Review *** Page 683 of 786 such species or habitat. Under this standard, 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 include both the

direct and indirect effects that will be added to t he

environmental baseline. 50 CFR 402.02. Direct effec ts are the

direct or immediate effects of an action on a liste d species or

its habitat. 577 Indirect effects are those that are “caused by the proposed action and are later in time, but stil l are reasonably certain to occur.” Id. To trigger the 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 reasonabl y certain to

occur. The EPA notes that the projected environmental effects of this final action are positive: reductions in overa ll GHG emissions, and reductions in PM and ozone-precursor emissions (SO X and NO X ). The EPA recognizes that beneficial effects to listed species can, as a general matter, result in a “may affect” determination under the ESA. However, the E PA’s

577 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 During Review *** Page 684 of 786 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 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 Federalfederal

and Statestate funding). See RIA chapter 4.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 685 of 786 With respect to the projected GHG emission reductio ns, the

EPA does not believe that such minor reductions tri gger ESA consultation requirements under section 7(a)(2). In reaching this conclusion, the EPA is mindful of significant legal and technical analysis undertaken by FWS and the U.S. D epartment of the Interior (DOI) in the context of listing the po lar 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. 578 The

DOI Solicitor concluded that where the effect at is sue 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 ad ditional consideration of GHG modeling tools and data regard ing listed

578 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).***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 686 of 786 species. The EPA evaluated this same issue in the c ontext of 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 579 and, based on air quality 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

579 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 During Review *** Page 687 of 786 action, given that the projected 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 Actio n v. U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a species from a federal action is extremely remote, ESA does not require co nsultation). The EPA’s conclusion is entirely consistent with DO I’s analysis regarding ESA requirements in the context of federa l actions involving GHG emissions. 580 The EPA received a comment on the proposal referenc ing a prior letter sent to the EPA by three U.S. Senators, 581 which

580 The EPA has received correspondence from a U.S. Senator and a MemberMembers of the U.S. House of Representatives notingCongress asserting that the Services have identified several listed species affected by global climate c hange. See Letter from Rob Bishop, Chairman, House Committee o n Natural Resources, to Gina McCarthy, Administrator, U.S. En vironmental Protection Agency, dated June 11, 2015; Letter from Rob Bishop, Chairman, House Committee on Natural Resources, and James M. Inhofe, Chairman, Senate Committee on Environment a nd Public Works, to Gina McCarthy, Administrator, U.S. Enviro nmental Protection Agency, dated June 15, 2015.The EPA’s assessment of ESA requirements in connection with the present rul e 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 section 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. 581 See Letter from David Vitter, James M. Inhofe, and Mik e Crapo, United States Senate Committee on Environmen t and Public***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 688 of 786

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 Impactsenergy 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 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 EGUs to trigger the NSPS modification or reconstruction provisions in t he period of analysis.

D. What are the Waterwater and Solid Waste Impactssolid 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

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 During Review *** Page 689 of 786 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 EGUs to trigger the NSPS modification or reconstruction pro visions in the period of analysis. Still there are expected to be a small number of coal plants with CCS and the use of CCS s ystems (especially post-combustion system) will increase t he amount of water used at the facility. If those plants utilize partial CCS to meet the final standard of performance (i.e., ap proximately 16 to 23 percent capture), the increased water use will not be significant. See Section V.O.2. The EPA is unaware of any solid waste impact resulting from this rule. 582

E. What are the Compliance Costscompliance costs ? For steam generating EGUs, the EPA has carefully an alyzed the costs of meeting the promulgated standard of pe rformance for a highly efficient SCPC using partial CCS and found these costs

to be reasonable. See Sections V.H and I above. Thi s analysis assumes new capacity not otherwise compliant with t he standards would be constructed. Based on the analysis in chap ter 4 of the RIA, the EPA believes the standards of performance for newly

582 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 During Review *** Page 690 of 786 constructed EGUs will have no notable compliance co sts, because electric power companies are expected to build new EGUs that comply with the regulatory requirements of this fin al rule even in the absence of the rule, primarily NGCC units, d ue to existing and expected market conditions. While the EPA’s analysis and projections from EIA continue to show that the rule is likely to result in negligible costs and benefit s due to existing generation choices, the EPA recognizes tha t some companies may choose to construct coal or other fos sil fuelfired units and has set standards for these units a ccordingly. For this reason, the RIA also analyzes project-leve l costs of a unit with and without CCS, to quantify the potentia l cost for a

fossil fuel-fired unit with CCS. 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 EGUs to trigger the NSPS modification or recons truction provisions in the period of analysis.

F. What are the Economiceconomic and Employment Impactsemployment 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 691 of 786 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. 583 As previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstruction pro visions. 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 Benefitsbenefits of the Final Standardsfinal

standards ? We are not projecting direct monetized climate bene fits in

terms of CO 2 emission reductions associated with these standard s of performance. This is because, as stated above, t he EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements o f this rule even in its absence, primarily NGCC units, because of existing and expected market conditions. See RIA chapter 4. Moreover, a

583 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 During Review *** Page 692 of 786 cost-reasonable standard is, in fact, what will dri ve new technology deployment and provide a path forward fo r new coalfired capacity. See Section V.L above. As also previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstructio n provisions. 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. XIV. 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 R eview and Executive Order 13563: Improving Regulation and Reg ulatory

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 693 of 786 (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, and Reconstructed Stationary Sources: Electric Util ity Generating Units” (EPA-452/R-15-005, 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 694 of 786 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 EGUs to trigger the NSPS modification or recons truction provisions in the period of analysis (through 2022) . In Chapter 6 of the RIA, we discuss factors that limit our abi lity to quantify the costs and benefits of the standards fo r modified

and reconstructed 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 2465.03. Separate ICR documents were prepared and submitted to OMB for th e proposed standards for newly constructed EGUs (EPA ICR numbe r 2465.02) and the proposed standards for modified and reconst ructed EGUs (EPA ICR number 2506.01). Because the CO 2 standards for newly constructed, modified, and reconstructed EGUs will be included in the same new subpart (40 CFR part 60, subpart TT TT) and are being finalized in the same action, the ICR documen t for this

action includes estimates of the information collec tion burden on owners and operators of newly constructed, modif ied, and***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 695 of 786

reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics (BLS) labor cost data. T hus, all

burden estimates are in 2013 dollars. Burden is def ined at 5 CFR 1320.3(b). You can find a copy of the ICR in the do ckets for this action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQOAR-2013-0603), and it is briefly summarized here. The information collection requirements are not enforce able 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 696 of 786 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 stationary combustion turbines) beyond what those s ources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information col lection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) und er the provisions of the Paperwork Reduction Act, 44 U.S.C . 3501 et seq. and has assigned OMB control numbers 2060-0626 and 2060- 0629, respectively. Apart from certain reporting co sts to comply with the emission standards under the rule, there a re no new information collection costs, as the information re quired by the standards for newly constructed EGUs is already col lected and reported by other regulatory 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 12 affected n ewly constructed NGCC units and 25 affected newly constr ucted natural***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 697 of 786 gas-fired simple cycle combustion turbines will com mence operation during that time period. As a result of t his final action, owners or operators of those newly construc ted 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 stationary c ombustion turbines). As previously stated, the EPA expects fe w EGUs to trigger the NSPS modification or reconstruction pro visions in the period of analysis. Specifically, the EPA belie ves it unlikely that fossil fuel-fired electric utility st eam generating units or stationary combustion turbines will take

actions that would constitute modifications or reco nstructions as defined under the EPA’s NSPS regulations. Accord ingly, the

standards for modified and reconstructed EGUs are n ot anticipated to impose any information collection bu rden over the 3-year period covered by this ICR. We have estimate d, however, the information collection burden that would be imp osed on an

affected 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 698 of 786 collection burden on those affected EGUs beyond wha t they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As described above, the OMB has previous ly approved the information collection requirements contained i n the existing part 75 and 98 regulations. Apart from cer tain reporting costs to comply with the emission standar ds under the rule, there would be no new information collection costs, as the information required by the final rule is already c ollected and reported by other regulatory 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 $1,333 and 16 labor hours. There are no annualized capital cos ts or O&M

costs associated with burden for modified or recons tructed 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 $60,977 and***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 699 of 786 651 labor hours. There are no annualized capital co sts or O&M costs associated with burden for newly constructed, modified, or reconstructed EGUs. Average burden hours per respon se are estimated to be 7 hours. The total number of respon dents over the 3-year ICR period is estimated to be 62. 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 stea m generating units without CCS to be built. We expect that any n ewly constructed natural gas-fired stationary combustion turbines***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 700 of 786 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-15-005, August 2015) for further discussion of sensitivities.) We have therefore concluded that this final action will have no net regulatory burden for all d irectly regulated small entities.

2. Modified and Reconstructed EGUs The EPA expects few fossil fuel-fired electric util ity steam generating units to trigger the NSPS modifica tion provisions in the period of analysis. An NSPS modif ication is defined as a physical or operational change that in creases the source’s maximum achievable hourly rate of emission s. The EPA does not believe that there are likely to be EGUs t hat will take***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 701 of 786

actions that would constitute modifications as defi ned under 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-15-005, 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 compliance costs on owners and operators of newly c onstructed***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 702 of 786 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-15-005, August 2015) for further discussion o f sensitivities.) As previously stated, the EPA expects few fossil fu el-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 analy sis. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not antic ipate that the rule would impose significant costs on those so urces. (See the “Regulatory Impact Analysis for the Standards o f Performance for Greenhouse Gas Emissions for New, Modified, and***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 703 of 786 Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA-452/R-15-005, 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 fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in t he period of analysis.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 704 of 786

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 fossil fuel-fired electric utility stea m generating units or natural gas-fired stationary combustion tu rbines to trigger the NSPS modification or reconstruction pro visions in the period of analysis. We, therefore, anticipate t hat the final rule will impose minimal compliance costs.

F. Executive Order 13175: Consultation and Coordina tion 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, 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 705 of 786 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 EGUs to trigger the NSPS modification or reconstruction pro visions in the period of analysis. Thus, the rule will neither impose substantial direct compliance costs on tribal gover nments nor preempt Tribal law. Accordingly, Executive Order 13 175 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 706 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 707 of 786 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 fr om 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 GHG that contributes to climate change and is emitted in significant quantities by fossil fuel -fired power plants. As stated above, the EPA believes the final rule will have negligible effects on owners and operators of newly***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 708 of 786 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 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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 709 of 786 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 Regula tions that Significantly Affect Energy Supply, Distribution, o r Use This final action is not a “significant energy acti on” because it is not likely to have a significant adve rse effect on the supply, distribution, or use of energy. See Sec tion V.O.3 above. The EPA believes that electric power compani es 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 fossil fuel-fired electric utility steam generating units or natural***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 710 of 786 gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the pe riod of analysis. Thus, this action is not anticipated to h ave notable impacts on emissions, costs or energy supply decisi ons for the affected electric utility industry. I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR part 51

This final action involves technical standards. The EPA has decided to use 10 voluntary consensus standards (VC S) 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 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- 1299 , “Standard Classification of Coals by Rank”;

D396- 13c98 , “Standard Specification for Fuel Oils”; D975- 1408a , “Standard Specification for Diesel Fuel Oils”; D369 9- 13b08 , “Standard Specification for Kerosene”; D6751- 1211b , “Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels”; and D7467- 1310 , “Standard Specification for***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 711 of 786 Diesel Fuel Oil, Biodiesel Blend (B6 to B20)” are c ited in the final rule to identify the different fuel types. Th ese standards 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 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 appendices A, B, D, F and G to 40 CFR part 75 and the procedures under 40 CFR 98.33;***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 712 of 786 these appendices contain standards that have alread y 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 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 713 of 786 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. Populations that were found to be pa rticularly vulnerable to climate change risks include the poor , the elderly, the very young, those already in poor heal th, the disabled, those living alone, and/or indigenous pop ulations 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 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. The record for the 2009 Endangerment Finding summar izes the strong scientific evidence in the major assessment reports by the U.S. Global Change Research Program (USGCRP), t he Intergovernmental Panel on Climate Change (IPCC), a nd the National Research Council (NRC) of the National Aca demies that the potential impacts of climate change raise envir onmental justice issues. These reports concluded that poor c ommunities can be especially vulnerable to climate change impa cts because***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 714 of 786 they tend to have more limited adaptive capacities and are 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 impacted by degradation of natural and cultur al resources

within established reservation boundaries and threa ts to traditional subsistence lifestyles. Tribal communit ies whose health, economic well-being, and cultural tradition s depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associa ted with climate change. The 2009 Endangerment Finding recor d also specifically noted that Southwest native cultures a re especially vulnerable to water quality and availability impact s. Native Alaskan communities are already experiencing disrup tive impacts, including coastal erosion and shifts in the range o r abundance of wild species crucial to their livelihoods and we ll-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations in the United States. 584 The new

584 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.***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 715 of 786 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 reports provides new information on how some communities of color may be uniquely vulnerable to climate change health impact s in the United States. These reports find that certain clim ate change related impacts—including heat waves, degraded air quality, and extreme weather events—have disproportionate effect s on lowincome and some communities of color, raising envir onmental justice concerns. Existing health disparities and o ther inequities in these communities increase their vuln erability to the health effects of climate change. In addition, assessment

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. 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 During Review *** Page 716 of 786 reports also find that climate change poses particu lar threats to health, wellbeing, and ways of life of indigenou s 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 the health and other adverse impacts of climate change.

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 717 of 786 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 fossil fuel-fired electric utility steam genera ting units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in t he period of analysis. This final rule will ensure that, to what ever extent there are newly constructed, modified, and reconstr ucted EGUs, they will use the best performing technologies to l imit

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). XV. Withdrawal of Proposed Standards for Certain Mo dified

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***EO 12866_Review - Draft – Do Not Cite, Quote or Release During Review *** Page 718 of 786 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 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)).Page 719 of 786

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, AdministratorPage 720 of 786

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); and 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.

* * * * * (d) The following material is available for purchas e from the American National Standards Institute (ANSI), 2 5 W. 43rdPage 721 of 786

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.

* * * * * (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.

* * * * *Page 722 of 786

(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) * * * (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 rea d as

follows: Subpart TTTT Standards of Performance for Greenhous e GasPage 723 of 786

Emissions for Electric 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 pollutants are regulated by this sub part? §60.5520 What CO 2 emissions standard must I meet? General Compliance Requirements §60.5525 What are my general requirements for compl ying with

this subpart? Monitoring and Compliance Determination Procedures §60.5535 How do I monitor and collect data to demon strate

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 r ecords? 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?Page 724 of 786

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 reconstruction after June 18, 2014 that meets the r elevant 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 commenced modification after June 18, 2014 that meets the relevant applica bility 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.Page 725 of 786

(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)(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 of its potential electric output or 219,000 MWh, whichever is greater. (2) Your EGU is capable of combusting 50 percent or more non-fossil fuel and is also subject to a federally enforceable permit condition limiting the annual capacity facto r for all fossil fuels combined of 10 percent (0.10) or less. (3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting annual net-electric sales to no more than the produ ct of the unit's net design efficiency and the unit's potenti al electric output or 219,000 MWh, whichever is greater. (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 ste am generating unit, IGCC, or stationary combustion turbine) is 25 MW or less. (5) Your EGU is a municipal waste combustor that is subject to subpart Eb of this part.Page 726 of 786

(6) Your EGU is a commercial or industrial solid wa ste incineration unit that is subject to subpart CCCC o f this part. (7) Your EGU is a steam generating unit or IGCC tha t undergoes a modification resulting in an hourly inc rease in CO 2 emissions (mass per hour) of 10 percent or less (2 significant figures). Modified units that are not subject to th e requirements of this subpart pursuant to this subse ction continue to be existing units under section 111 wit h respect to

CO 2 emissions standards. (8) Your EGU is a stationary combustion turbine tha t is not capable of combusting natural gas (e.g., not connec ted to a natural 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 StandardsPage 727 of 786

§60.5515 Which pollutants are regulated by this sub part? (a) The pollutants regulated by this subpart are gr eenhouse

gases. The greenhouse gas standard in this subpart is in the

form of a limitation on emission of carbon dioxide. (b) PSD and Title V Thresholds for Greenhouse Gases

. (1) For the purposes of 40 CFR §51.166(b)(49)(ii), with respect to GHG emissions from affected 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 §51.166(b)(48) and in any SIP app roved by the EPA that is interpreted to incorporate, or spec ifically incorporates, §51.166(b)(48) of this chapter. (2) For the purposes of 40 CFR §52.21(b)(50)(ii), w ith respect to GHG emissions from affected facilities, 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)(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 CFRPage 728 of 786

§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 40 CFR §71.2 of this 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 Table 1 or Table 2 of this subpart, consistent with paragraphs (b )), (c), and ( cd ) of this section, as applicable. (b) Except as specified in paragraphparagraphs (c) and (d)

of thethis 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 aPage 729 of 786

stationary combustion turbine may petition the Admi nistrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the pe tition, beginning on the date the Administrator grants the petition, the affected EGU must comply with the applicable net en ergy output based standard included in this subpart. Your opera ting permit must include monitoring, recordkeeping, and reporti ng methodologies based on the applicable net energy ou tput standard. For the remainder of this subpart, where the term “gross or net energy output” is used, the term that applies to you is “net energy output.” Owners or operators com plying with the net output based standard must petition the Adm inistrator to switch back to complying with the gross energy outp ut 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 160Page 730 of 786

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

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 compl ying with this subpart? ComplianceCombustion 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 TablesTable 1 - or 2 for the applicable CO 2Page 731 of 786

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 determine compliance monthly by calculating th e average CO 2 emissions rate for the affected EGU at the end of t he initial and each subsequent 12-operating - month period. (2) For eachConsistent with §60.5520(d)(2), if your

affected EGUstationary combustion turbine is subject to thean input-based CO 2 emissions standard for multi-fuel units , you must determine the total heat input in million Btu’s (MM Btu) 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 equ ation to determine the applicable emissions standard (EL) during the compliance period:

 emission	standard	= 120 x HTIP

  +  160 x HTIP   Total	Heat	Input	from	All	Fuels 120		x	HTIP   +  160		x	HTIP   HTIP  + HTIP

 Where:Page 732 of 786

CO 2 emission standard = the emission standard during t he

compliance period in units of lb/ MMbtuMMBtu

. HTIP ng = the heat input in MMBtu from natural gas during the

compliance pe riod

. HTIP o = the heat input in MMBtu from all fuels other tha n

natural gas that were fired during the compliance period

. 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. (b) At all times you must operate and maintain each affected EGU, including associated equipment and monitoring equipmentmonitors , 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-operatingPage 733 of 786

- 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 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 notPage 734 of 786

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). (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 demon strate compliance? (a) YouCombustion 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 f or permitted fuel(s). If your combustion turbine uses non-unifor m fuels as specified under §60.5520(d)(2), you must monitor he at input in accordance with paragraph (c)(1) of this section, a nd you mustPage 735 of 786

monitor CO 2 emissions in accordance with either paragraph (b), (c)(2), or (c)(5) of this section. For all other af fected

sources, you must prepare a monitoring plan to quantify the hourly CO 2 mass emission rate (tons/ hrh ), in accordance with the applicable provisions in §75.53(g) and (h) of this chapter. The electronic portion of the monitoring plan must be s ubmitted using the ECMPS Client Tool and must be in place pr ior to reporting emissions data and/or the results of moni toring system certification tests under this subpart. The monitor ing plan must be updated as necessary. Monitoring plan submittals must be made by the Designated Representative (DR), the Alternat e DR, or a delegated agent of the DR (see §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 to directPage 736 of 786

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 monitoring system, according to §75.11(b) of this c hapter. Alternatively, you may either use an appropriate fu el-specific default moisture value from §75.11(b) or submit a p etition to the Administrator under §75.66 of this chapter for a sitespecific 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 youPage 737 of 786

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. 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/ hrh ), 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/ hrh 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 mus t use thesePage 738 of 786

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

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 st andard 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/ hrh ). You may determine sitespecific 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 ratePage 739 of 786

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

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 th e basis of the emissions standard that applies to your affe cted source in accordance with either paragraph (d)(1) or (d)(2 ), asPage 740 of 786

applicable: (1) If you operate a source subject to an emissions standard established on an output basis (e.g., lbs of CO 2 per gross or net MWh of energy output), you must instal l, 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 re ference, see 60.17). For a combined heat and power (CHP) EGU, as defined 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., lbs oflb CO2 per / MMBtu of heat input) and your affected source uses nonuniform heating value fuels as delineated under §60 .5520(d ), you must determine the total heat input for each fuel f ired duringPage 741 of 786

the compliance period in accordance with one of the following procedures: (i) Appendix D to Part 75; (ii) The procedures for monitoring heat input under of 40 CFR § 60.107a(d); or (iii) The procedure for monitoring heat input under 40 CFR 98.33(a)(2) or (a)(3). (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 affect ed 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.Page 742 of 786

(f) In accordance with §60.13(g) and §60.5520, if t wo 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 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 th e 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 chapte r) at each stack or duct separately. In this case, you must de termine compliance with the applicable emissions standard i n Table 1 orPage 743 of 786

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. h) Heat rate determination and design efficiency fo r combustion turbines. Acceptable methods include the following testing and analytical methods: (1) ASME PTC 6-2004 Steam Turbines (incorporated by reference, see §60.17). (2) ASME PTC 6S Procedures for Routine Performance Test of Steam Turbines (incorporated by reference, see §60. 17). (3) ASME PTC 6.2-2011 Steam Turbines in Combined Cy cles (incorporated by reference, see §60.17). (4) ASME PTC 22 Gas Turbines (incorporated by refer ence, see §60.17). (5) ASME PTC 46 Overall Plant Performance (incorpor ated by reference, see §60.17). (6) ISO 2314:2009 Gas turbines – acceptance tests (incorporated by reference, see §60.17). (7) DIN 1943 Thermal Acceptance of steam turbines (incorporated by reference, see §60.17). (8) IEC-953-2 Rules for steam turbine thermal accep tance tests. Part 2: Method B - Wide range of accuracy fo r various types and sizes of turbines (incorporated by refere nce, see §60.17).Page 744 of 786

§60.5540 How do I demonstrate compliance with my CO 2 emissions

standard? (a) In accordance with § 60.5520, toif you are subject to an output based emission standard or you burn non-u niform 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 either the generating load data from §60.5535(d)(1) for output-based calculations or the heat input data from §60.5535(d)(2) for heat-input-based calculations. Combustion turbines firing non-unifor m fuels that

contain CO 2 prior to combustion (e.g., blast furnace gas or landfill gas) may sample the fuel stream to determi ne the quantity of CO 2 present in the calculationsfuel prior to combustion and exclude this portion of the CO 2 mass emissions from compliance determinations

.Page 745 of 786

(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, if a heat input based standard applies, all the parameters used to determine total heat input f or 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.Page 746 of 786

(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) 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 equalPage 747 of 786

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) val ue reported under part 75 of this chapter to MWh, multiply by t he corresponding EGU or stack operating time.

$ %&&/() =  $*  +, +  $*  -, +  $*  ./ − $* 12 − $* 3 TDF

+ 5  $6  7+ +  $6  89 +  $6  ./ :

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

output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanicalPage 748 of 786 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. (Pt) IE = Useful thermal output (relative to SATP

conditions, as applicable) from any integrated equipment is used for applications that do notPage 749 of 786 generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh.

TDF = Electric Transmission and Distribution Facto r 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.

(ii) If applicable to your affected EGU (for exampl e, for combined heat and power), you must calculate (Pt) PS using the following equation: $6 7+ = < = × 	? @

Where: 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, asPage 750 of 786 applicable) in Joules per kilogram (J/kg) (or Btu/lb).

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. Sourc es 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. (ii) If you are subject to a heat input based stand ard, you must calculate the total heat input for each fuel f ired during the compliance period. The calculation of total hea t input for each individual fuel must include all valid operati ng hours and must also be consistent with any fuel-specific proc eduresPage 751 of 786

specified within your selected monitoring option un der §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)(i) of this section. Round off the result to two significa nt figures if the calculated value is less than 1,000; round the result to three significant figures if the calculated value i s greater than 1,000 . If you are subject to a heat input based standard , you must calculate the CO 2 mass emissions rate for the affected EGU(s) (lb/MMBtu) by dividing the total CO 2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total heat input calculated acc ording to the procedures in paragraph (a)(6)(ii) of this section. Round off the result to two significant figures. (b) In accordance with §60.5520, to demonstrate com pliance 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 toPage 752 of 786

the applicable CO 2 emissions standard in Table 1, Table 2, or 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 affec ted 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 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 ollowingPage 753 of 786

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 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 (asPage 754 of 786

identified in Table 1 or 2) with which your affecte d EGU must comply; and (vi) Consistent with §60.5520, an indication whethe r 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 o r net energy output sold to an electric grid, as applicab le to the units of your emission standard, over the 4 quarter s of the calendar year; and (ii) The potential electric output of the EGU. (b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions 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 tingPage 755 of 786

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 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)Page 756 of 786

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 ener gy output data on that date. Otherwise, emissions data report ing shall be on a gross energy output basis until the date that the Client Tool is first able to receive and process net energ y 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 (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 sectionPage 757 of 786

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 Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submiss ions to one

or more persons. (f) If your affected EGU captures CO 2 to meet the applicable emission limit, you must report in accordance with the requirements of 40 CFR Part 98 Subpart PP and eithe r: (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.Page 758 of 786

(3) Transfer the captured CO 2 to a facility that has received an innovative technology waiver from EPA pursuant to p aragraph (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 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 anyPage 759 of 786

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. (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;Page 760 of 786

(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; (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);Page 761 of 786

(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. (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 r ecords? (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 l ocation by aPage 762 of 786

computer or other means that instantly provide acce ss at the site meet this requirement. You may maintain the re cords off site for the remaining year(s) as required by this subpart. Other Requirements and Information §60.5570 What parts of the General Provisions apply to my

affected EGU? Notwithstanding any other provision of this chapter , certain parts of the General Provisions in §60.1 th rough 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 retainsPage 763 of 786

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 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, 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 ofPage 764 of 786

Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Synth etic 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,

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 lo wer heating value basis at the base load rating, at ISO conditi ons, and at the maximum useful thermal output (e.g., CHP unit w ithPage 765 of 786

condensing steam turbines would determine the desig n efficiency at the maximum level of extraction and/or bypass). Design efficiency shall be determined using one of the fol lowing methods: ASME PTC 22 Gas Turbines (incorporated by reference, see §60.17), ASME PTC 46 Overall Plant Performance (incorporated by reference, see §60.17) or ISO 2314:2009 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 fue l 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 anyPage 766 of 786

form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, 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 steam generating units, the gross electric or mechanical output from the affected EGU(s) (includi ng, but not limited to, output from steam turbine(s), combustio n turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful ther mal 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-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), combustio n turbine(s),Page 767 of 786

and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boi ler feedwater pumps is not applicable to IGCC facilities), that d ifference divided by 0.95, plus 100 percent of the useful the rmal output. Heat recovery steam generating unit (HRSG) means an EGU in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used

with or without duct burners. Integrated gasification combined cycle 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 is not used to operate the affected EGU(s), generat e electricityPage 768 of 786

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. Finally, natural gas do es not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-der ived gas, producer gas, coke oven gas, or any gaseous fuel pr oduced in a process which might result in highly variable 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 of the total gross energy output consists of useful thermal output on an annual basis, the gross electric sales to thePage 769 of 786

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 system e mergency are not included when calculating net-electric sale s. 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 (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 usefulPage 770 of 786

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. Potential electric output means 33 percent or the base load rating design efficiency at the maximum electr ic production rate (e.g., CHP units with condensing st eam turbines will operate at maximum electric productio n), whichever is greater, multiplied by the base load r ating (expressed in MMBtu/h) of the EGU, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,0 00 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).Page 771 of 786

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 subcomponents 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 turbinePage 772 of 786

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 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 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 thermalPage 773 of 786

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 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. Fo r CEMS, thePage 774 of 786

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 fu el 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 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.Page 775 of 786

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, as approved by the Administrator) Note: numerical values of 1,000 or greater have a m inimum of 3 significant figures and numerical values of less th an 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) 640 kg CO 2 /MWh of gross energy output (1,400 lb CO 2 /MWh)

Reconstructed steam generating unit or IGCC 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.Page 776 of 786

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 after June 18, 2014 (net energy output-based standards applicable as approved by the Administrator) Note: numerical values of 1,000 or greater have a m inimum of 3 significant figures and numerical values of less th an 1,000 have

a minimum of 2 significant figures Affected EGU CO 2 Emission Standard 585 Newly constructed or reconstructed stationary combustion turbine that supplies more than theits design efficiency times theits 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 470 kilograms (kg) of CO 2 per megawatt-hour (MWh) of net energy output (1,030 lb/MWh)

Newly constructed or reconstructed stationary combustion turbine that supplies theits design efficiency times theits 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 heat input basis on a 12-operating - month rolling average basis. 50 kg CO 2 per gigajoule (GJ) of heat input (120 lb CO 2 /MMBtu)

Stationary 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

585 See procedures for establishing and revising the co mpliance option under § 60.5520.Page 777 of 786

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 75Page 778 of 786

§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.Page 779 of 786

PART 70— STATE OPERATING PERMIT PROGRAMS 4. The authority citation for part 70 continues to read as

follows: Authority : 42 U.S.C. 7401 et seq. 5. Section 70.2 is amended by revising the introduc tory 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.

* * * * * 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.

* * * * * (b) * * * (2)(i) The Administrator will presume that the fee schedulePage 780 of 786

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) GHG evaluation for a permit modification or related permit action GHG evaluation at permit renewal 43

7

10

* * * * *Page 781 of 786

PART 71— FEDERAL OPERATING PERMIT PROGRAMS 7. The authority citation for part 71 continues to read as

follows: Authority : 42 U.S.C. 7401 et seq. 8. Section 71.2 is amended by removing “or” from th e 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.

* * * * * 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).

The revisions and additions read as follows: §71.9 Permit fees.

* * * * *Page 782 of 786

(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 (B) Any GHG fee adjustment required under paragraph (c)(8)

of this section.

* * * * *Page 783 of 786

(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. (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 ofPage 784 of 786

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 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 REPORTINGPage 785 of 786

10. The authority citation for part 98 is revised t o read

as follows: Authority: 42 U.S.C. 7401-7671q. Subpart PP—Suppliers of Carbon Dioxide 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 (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.

* * * * *Page 786 of 786

(d) Facilities subject to §98.426(h) must retain r ecords of

CO 2 in metric tons that is transferred to each subpart RR facility.