*** EO 12866 Review
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- 50 **ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 60, 70, 71, and 98**  **[EPA -** **HQ -** **OAR -**  **2013 -**  **0495; EPA -** **HQ -** **OAR -**  **2013 -**  **0603; FRL -** **XXXX -** **XX -** **OAR] RIN 2060**  **- AQ91**  **Standards of Performance for Greenhouse Gas Emissions from New ,**  **Modified, and Reconstructed Stationary Sources: Electric Utility**  **Generating Units AGENCY:**  Environmental Protection Agency (EPA). **ACTION:** Final rule. **SUMMARY:** The Environmental P rotection Agency ( EPA ) is finalizing 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 fossil fuel
fired electric utility generating units (EGUs) . This action establishes separate standards of performance for fossil fuel
fired electric utility steam generating units and fossil fuel
fired stationary combustion turbines. This action also addresses related permitting and reporting issues. In a separate action, under CAA section 111(d), the EPA is issuing final emission***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **2** of **763** guidelines for states to use in developing plans to limit CO 2 emissions from existing fossil fuel
- fired E GUs. **DATES:** This final rule is effective on [ **insert date 60 days after date of publication in the federal register**  ]. **ADDRESSES:** The EPA has established dockets for this action under Docket ID No. EPA- HQ - OAR- 2013
- 0495 ( Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. EPA- HQ - OAR- 2013
- 0603 ( Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units). All documents in the dockets are listed on the www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g., Confidential Business Information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in www.regulations.gov or in hard copy at the EPA Docket Center (EPA/DC), Room 3334, EPA WJC West Building, 1301 Constitution Ave. NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566
- 1744, and the telephone number for the Air Docket is (202) 566
- 1742.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **3** of **763 FOR FURTHER INFORMATION CONTACT:**  Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Division (D243
- 01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541
- 2968, facsimile number (919) 541
- 5450; email address: hutson.nick@epa.gov or Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243
- 01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541
- 4003, facsimile number (919) 541
- 5450; email address: fellner.christian@epa.gov. **SUPPLEMENTARY INFORMATION:** Acronyms . A number of acronyms and chemical symbols are used in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference purpo ses, the following terms and acronyms are defined as follows: AB Assembly Bill AEO Annual Energy Outlook AEP American Electric Power ANSI American National Standards Institute ASME American Society of Mechanical Engineers ASTM American Society for Testing of Materials BACT Best Available Control Technology BDT Best Demonstrated Technology BSER Best System of Emission Reduction Btu/kWh British Thermal Units per Kilowatt
-hour Btu/lb British Thermal Units per Pound CAA Clean Air Act CAIR Clean Air Interstate Rule CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration) CDX Central Data Exchange CEDRI Compliance and Emissions Data Reporting Interface CEMS Continuous Emissions Monitoring System CFB C irculating Fluidized Bed***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **4** of **763** 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 System EERS Energy Efficiency Resource Standards EGU Electric Generating Unit EIA Energy Information Administration EO Executive Order EOR Enhanced Oil Recovery EPA Environmental Protection Agency FB Fluidized Bed FGD Flue Gas Desulfurization FOAK First
- of - a - kind FR Federal Register GHG Greenhouse Gas GHGRP Greenhouse Gas Reporting Program GPM Gallons per Minute GS Geologic Sequestration GW Gigawatts H 2 Hydrogen Gas HAP Hazardous Air Pollutant HFC Hydrofluorocarbon HRSG Heat Recovery Steam Generator IGCC Integrated Gasification Combined Cycle IPCC Intergovernmental Panel on Climate Change IPM Integrated Planning Model IRPs Integrated Resource Plans kg/MWh Kilogram per Megawatt
-hour kJ/kg Kilojoules per Kilogram kWh Kilowatt
-hour lb CO 2 /MMBtu Pounds of CO 2 per Million British Thermal Unit lb CO 2 /MWh Pounds of CO 2 per Megawatt -hour lb CO 2 /yr Pounds of CO 2 per Year lb/lb
-mole Pounds per Pound-Mole LCOE Levelized Cost of Electricity MATS Mercury and Air Toxic Standards MMBtu/hr Million British Thermal Units per Hour MRV Monitoring, Reporting, and Verification MW Megawatt MWe Megawatt Electrical MWh Megawatt -hour MWh - g Megawatt -hour gross MWh - n Megawatt -hour net N 2O Nitrous Oxide***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **5** of **763** NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System 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 O2 Oxygen Gas OMB Office of Management and Budget PC Pulverized Coal PFC Perfluorocarbon PM Particulate Matter PM2.5 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 Ana lysis RPS Renewable Portfolio Standard RTC Response to Comments RTP Response to Petitions SBA Small Business Administration SCC Social Cost of Carbon SCR Selective Catalytic Reduction SCPC Supercritical Pulverized Coal SDWA Safe Drinking Water Act SF 6 Sulfur Hexafluoride SIP State Implementation Plan SNCR Selective Non
- Catalytic Reduction SO 2 Sulfur Dioxide SSM Startup, Shutdown, and Malfunction Tg Teragram (one trillion (10 12 ) grams) Tpy Tons per Year TSD Technical Support Document TTN Technology Transfer Network UIC Underground Injection Control UMRA Unfunded Mandates Reform Act of 1995 U.S. United States USDW Underground Source of Drinking Water USGCRP U.S. Global Change Research Program VCS Voluntary Consensu s Standard***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **6** of **763** WGS Water Gas Shift WWW World Wide Web Organization of This Document . The information presented in this preamble is organized as follows: **I. General Information** A. Executive Summary B. Does this action apply to me? C. Where can I get a copy of this document? D. Judicial Review E. How is this preamble organized ? **II. Background** A. Climate Change Impacts from GHG Emissions B. GHG Emissions from Fossil Fuel
- fired EGUs C. The Utility Power Sector D. Statutory Background E. Regulatory Background F. Development of Carbon Pollution Standards for Fossil Fuel
f ired Electric Utility Generating Units G. Stakeholder Engagement and Public Comments on the Proposals **III. Regulatory Authority,**  **Affected EGUs and Their Standards,**  **and Legal Requirements** A. Authority to Regulate C arbon Dioxide from Fossil Fuel
- fired EGUs B. Treatment of Categories and Codification in the Code of Federal Regulations C. Affected Units D. Units Not Covered by This Final Rule E. Coal Refuse F. Format of the Output -based Standard G. CO 2 Emissions Only H. Legal Requirements for Establishing Emission Standards I. Severability J. Certain Projects under Development **IV. Summary of Final**  **Standards for Newly Constructed, Modified,**  **and Reconstructed Fossil Fuel -**  **fired Electric Utility Steam Generating Units**  A. Applicability Requirements and Rationale B. Best System of Emission Reduction C. Final Standards of Performance **V. Rationale**  **for Final Standards for Newly Constructed Fossil Fuel**  **- fired Electric Utility Steam Generating Units**  A. Factors Considered in Determining the BSER B. Highly Efficient SCPC EGU Implementing Partial CCS a s the BSER for Newly Constructed Steam Generating Units***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **7** of **763** C. Rationale for the Final Emission Standards D. Post - Combustion Carbon Capture E. Pre - Combustion Carbon Capture F. Vendor Guarantees, Industry Statements, Academic Literature , and Commercial Availability G. Response to Key Comments on the Adequacy of the Technical Feasibility Demonstration H. Consideration of Costs I. Key Comments Regarding EPA’s Consideration of Costs J. Achievability of the Final Standards K. Emission Reductions Utilizing Partial CCS L. Further Development and Deployment of CCS Technology M. Technical and Geographic Aspects of Disposition of Captured CO 2 N. Final Requirements for Disposition of Captured CO 2 O. Nonair Quality Impacts and Energy Requirements P. Options That Were Considered by EPA but Were Ultimately Not Determined to Be the BSER Q. Summary **VI. Rationale**  **for Final Standards for Modified Fossil Fuel -**  **fired Electric Utility Steam Generating Units**  A. Rationale for Final Applicability Criteria for Modified Steam Generating Units B. Identification of the Best System of Emission Reduction C. BSER Criteria **VII. Rationale**  **for Final Standards for Reconstructed Fossil Fuel**  **- fired Electric Utility Steam Generating Un** **its** A. Rationale for Final Applicability Criteria for Reconstructed Sources B. Identification of the Best System of Emission Reduction **VIII. Summary of Final Standards**  **for Newly Constructed and Reconstructed Stationary Combustion Turbines**  A. Applicability Requirements B. Best System of Emission Reduction C. Final Emission Standards **IX. Rationale**  **for Final Standards for Newly Constructed and Reconstructed Stationary Combustion Turbines**  A. Applicability B. Subcategories C. Identification of the Best System of Emission Reduc tion D. Achievability of the Final Standards **X. Summary of Other Final Requirements for Newly Constructed, Modified, and Reconstructed Fossil Fuel**  **- fired Steam Generating**  **Units and Stationary Combustion Turbines** A. Startup, Shutdown, and Malfunction Requirements B. Continuous Monitoring Requirements C. Emissions Performance Testing Requirements***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **8** of **763** D. Continuous Compliance Requirements E. Notification, Recordkeeping, and Reporting Requirements **XI. Consistency b** **etween BSER Determinations for This 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 **X I**  **I .**  **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 GHGs F . Interactions with Other EPA Rules **XI I**  **I . 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 ec onomic 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 Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Re duction Act (PRA) C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act (UMRA) E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act (NTTAA) J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low
- Income Populations K. Congressional Review Act (CRA) **XV. Withdrawal of Proposed Standards for Certain Modified**  **Sources X**  **V I**  **. Statutory Authority**  **I. General Information*****EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **9** of **763** A. Executive Summary 1. Purpose of the Regulatory Action In this final action the EPA is establishing standards that limit greenhouse gas (GHG) emissions from newly constructed, modified, and reconstructed fossil fuel
- fired electric utility steam generating units and stationary combustion turbines , following the issuance of proposals for such standards and an accompanying Notice of Data Availability. On June 25, 2013, in conjunction with the announcement of his Climate Action Plan (CAP), President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to address carbon pollution from new power plants by September 30, 2013, and to issue “standards, regulations, or guidelines, as appropriate, which address carbon pollution from modified, reconstructed, and existing power plants.” Pursuant to authority in section 111(b) of the CAA, on September 20, 2013, EPA issued proposed carbon pollution standards for newly constructed fossil fuel - fired power plants. The proposal was published in the **Federal Register** on January 8, 2014 ( 79 FR 1430 ; “January 2014 proposal”). 1 In that proposal , the EPA proposed to limit

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 turbines based***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **10** of **763** emissions of CO 2 from newly constructed fossil fuel
- fired electric utility steam generating units and newly constructed natural gas - fired stationary combustion turbines. The EPA subsequently issued a Notice of Data Availability (NODA) in which the EPA solicited comment on its initial interpretation of provisions in the Energy Policy Act of 2005 (EPAct05) and associated provisions in the Internal Revenue Code (IRC) and also solicited comment on a companion Technical Support Document (TSD) that addressed these provisions’
relationship to the factual record supporting the proposed rule. 79 FR 10750 (February 26, 2014). On June 2, 2014, the EPA proposed standards of performance, also pursuant to CAA section 111(b), to limit emissions of CO 2 from modified and reconstructed fossil fuel
- fired electric utility steam generating units and natural gas
- fired stationary combustion turbines. 79 FR 34959 (June 18, 2014) (“June 2014 proposal”). Specifically, the EPA proposed standards of performance for : (1) modified fossil fuel
- fired steam generating units, (2) modified natural gas
- fired stationary combustion turbines, (3) reconstructed fossil fuel
- fired steam generating units, and (4) reconstructed natural gas
- fired stationary combustion turbines. on a single Best System of Emission Reduction determination. On January 8, 2014, the EPA withdrew that proposal (79 FR 1352).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **11** of **763** In this action, the EPA is issuing final standards of performance to limit emissions of GHG pollution manifested as CO 2 from newly constructed, modified, and reconstructed fossil fuel
fired electric utility steam generating units (i.e., utility boilers and int egrated gasification combined cycle (IGCC) units) and from newly constructed and reconstructed stationary combustion turbines. Consistent with the requirements of CAA section 111(b), these standards reflect the degree of emission limitation achi evable through the application of the best system of emission reduction (BSER) that the EPA has determined has been adequately demonstrated for each type of unit. These final standards are codified in 40 CFR part 60 , subpart TTTT, a new subpart specifically created for CAA 111(b) standards of performance for GHG emissions from fossil fuel
- fired EGUs . In a separate action that affects the same source category , the EPA is issuing final emission guidelines under CAA section 111(d) for states to use in developing plans to limit CO 2 emissions from existing fossil fuel
- fired EGUs. Pursuant to those guidelines, s tates must submit plans to the EPA following a schedule set by the guidelines. The EPA received numerous comments and conducted extensive outreach to stakeholders for this rulemaking. After careful consideration of public comments and input from a variety of stakeholders, the final standards of performance in this action***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **12** of **763** reflect certain changes from the proposals . Comments considered include written comments that were submitted during the public comment period and oral testimony provided during the public hearing for the proposed standards. 2. Summary of Major Provisions and Changes to the Proposed St andards The BSER determinations and final standards of performance for affected newly constructed, modified, and reconstructed EGUs are summarized in Table 1 and discussed in more detail below . The final standards for new, modified, and reconstructed EGUs apply to sources that commenced construction

– or modification 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 EGUs apply to those sources that commenced construction on or after the date of publication of the proposed standards, January 8, 2014. The final standards for modified and reconstructed fossil fuel - fired EGUs apply to those sources that modify or reconstruct on or after the date of publication of the proposed standards, June 18, 2014. **Table 1. Summary of BSER and Final Standards for Affected**  **EGUs Affected EGUs**  **BSER Final**  **Standard s of** 

2 See CAA 111(a)(2).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **13** of **763 Performance** 
Newly Constructed Fossil Fuel
Fired 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 input ≤ 2,000 MMBtu/h.

Reconstructed Fossil Fuel
Fired Steam Generating Units Most efficient generating technology at the affected source (supercritical steam 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **14** of **763** conditions for the larger; and subcritical conditions for the smaller) 2,000 lb CO 2 /MWh - g .

Newly Cons tructed and Reconstructed Fossil Fuel
Fired Stationary Combustion Turbines Efficient NGCC technology for base load natural gas fired units and clean fuels for non base load and multi
fuel - fired units 3 1. 1,000 lb CO 2 /MWh - g or 1,03 0 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 multi
fuel - fired units. 4

a. Fossil fuel
- fired electric utility steam generating units . This action establishes standards of performance for newly constructed fossil fuel
- fired steam generating units 5 based on

3 The term "multi
- fuel - fired" refers to a stationary combustion turbine that is physically connected to a natural gas p ipeline, but that burns a fuel other than natural gas for 10 percent or more of the unit's heat input capacity during the 12
- operating month compliance period. 4 The emission standard for combustion turbines co
- firing natural gas with other fuels shall be determined at the end of each operating month based on the amount of co
- fired natural gas. Units only burning natural gas with other fuels with a relatively consistent chemical composition and an emission factor of 160 lb CO 2 /MMBtu or less (e.g., natural gas, distillate oil, etc.) only need to maintain records of the fuels burned at the unit to demonstrate compliance. Units burning fuels with variable chemical composition or with an emission factor greater than 160 lb CO 2 /MMBtu (e.g., residual oil) must conduct periodic fuel sampling and testing to determine the overall CO 2 emission rate. 5 Also referred to as just “steam generating units” or as “utility boilers and IGCC units”. These are units that are covered under 40 CFR part 60, subpart Da for criteria pollutants.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **15** of **763** 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 comments , technical input received on the availability, technical feasibility, and cost of CCS implementation, and publicly available information about projects that are implementing or planning to implement CCS, the EPA confirms its proposed determination that CCS technology is available and technically feasible to implement at fossil fuel
- fired steam generating units. However, the EPA’s final standard reflects the
cons ideration of legitimate concerns regarding the cost to implement available CCS technology on a new steam generating unit. Accordingly, the EPA is finalizing an emission standard for newly constructed fossil fuel
- fired steam generating 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 reflects our identification of the BSER for such units to be a lower level of partial CCS than we identified as the basis of the proposed standards

– one that we conclude better represents the requirement that the BSER be implementable at reasonable cost. The EPA proposed that the BSER for newly constructed steam generating EGUs was highly efficient new generating technology***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **16** of **763** (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 EGUs in the final rule is very similar to that in the January 2014 proposal . In this final action, the EPA finds that a highly efficient 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 technology

– either with natural gas co
- firing or implementing partial CCS

– is not part of the BSER, but recognizes that IGCC technology can
serve as an alternative method of compliance. The EPA finds that a highly efficient SCPC implementing partial CCS is the BSER because CCS technology has been demonstrated to be technically feasible and is in use or under construction in various industrial sectors , including the power generation sector . For example, the Boundary Dam Unit #3 CCS project in Saskatchewan, Canada is a full
- scale, fully integrated CCS project that is currently operating and is designed to capture more than 90 percent of the CO 2 from the
6 Using the most recent data on partial capture rates 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
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– Do Not Cite, Quote or Release During Review *** Page **17** of **763** lignite
- fired boiler. A newly constructed , highly efficient SCPC utility boiler burning bituminous coal will be able to meet this final standard of performance by capturing and storing approximately 16 percent of the CO 2 produced from the facility. A newly constructed, highly efficient SCPC utility boiler burning subbituminous coal or dried lignite 7 will be able to meet this final standard of performance by capturing and storing 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 meet the final standard of performance by co - firing with natural gas. This final standard of performance for newly constructed fossil fuel
fired steam generating units provides a clear and achievable path forward for the construction of such sources while address ing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO 2 /MWh - g is achievable by fossil fuel
- fired steam generating units for all fuel types,

7 For a summary of lignite drying technologies , see “Techno economics of modern pre
- drying technologies for lignite
- fired power plants” available at www .iea
coal.org.uk/documents/83436 /9095/Techno
- economics
- of -modern -pre drying
- technologies
- for - lignite
- fire d-power -plants, - CCC/241; “Drying the lignite prior to combustion in the boiler is thus an effective way to increase the thermal efficiencies and reduce the CO 2 emissions from lignite
- fired power plants.”***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **18** of **763** under a wide range of conditions, and throughout the United States. We note that identifying a highly efficient new SCPC EGU implementing partial CCS as the BSER provide s a path forward for
new fossil fuel - fired steam generation in the current market context . Numerous studies have predicted that few new fossil fuel - fired steam generating units will be constructed in the future . These analyses identify a range of factors unrelated to this rulemaking , including low electricity demand growth, highly competitive natural gas prices, and increases in the supply of renewable energy. The EPA recognizes that , in certain circumstances , there may be interest in building fossil fuel - fired steam generating units despite these market conditions . In particular, utilities and project developers may build new fossil fuel
- fired steam generating EGUs in order to achieve or maintain fuel diversity within generating fleets , as
a hedge against the possibility of natural gas prices far exceeding projections , or to co -produce both power and chemicals , including capturing CO 2 for use in enhanced oil recovery (EOR) projects . 8 As regulatory history has shown,

8 As the EIA has stated: Policy
- related factors, such as environmental regulations and investment or production tax credits for specified generation sources, can also impact***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **19** of **763** identifying a new highly efficient S CPC EGU implementing partial CCS as the BSER in this rule is likely to further boost research and development in CCS technologies , making the implementation even more efficacious and cos t - effective , while providing a competitive, low emission future for fossil fuel - fired steam generation . The EPA is also issuing final standards for steam generating units that implement “ large modifications , ” ( i.e. , modifications resulting in an increase in hourly CO 2 emissions of more than 10 percent when compared to the source’s highest hourly emissions in the previous 5 years). 9 The EPA is not issuing final standards, at this time, for steam generating
investment decisions. Finally, although levelized cost calculations are generally made using an assumed set 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_generation.cfm

9 40 CFR 60.14(h)

– “No physical change, or change in the method of operation, at an existing electric utility steam generating unit shall be treated as a modification for the purposes of this se ction provided that such change does not increase the maximum hourly emissions of any pollutant regulated under this section above the maximum hourly emissions achievable at that unit during the 5 years prior to the change. ”***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **20** of **763** units that implement “ small modifications ” ( i.e. , modifications resulting in an increase in hourly CO 2 emission s of less than or equal to 10 percent when compared to the source’s highest hourly emissions in the previous 5 years) . The standards of performance for modified steam generating units that make large modifications are based on each affected unit’s own best potential performance as the BSER. Specifically, such a modified steam generating unit will be required to meet a unit
- specific CO 2 emission limit determined by that unit's best demonstrated historical performance (in the years from 2002 to the time of the modification). 10 The EPA has determined that this standard based on each unit’s own best potential performance can be met through a combination of best operating practices and equipment upgrades and that these steps can be implemented cost
effectively at the time when a source is undertaking a large modification . To account for facilities that have already implemented bes t practices and equipment upgrades, the final rule also specifies that modified facilities will not have to meet an emission standard more stringent than the corresponding 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
10 For the 2002 reporting year the EPA introduced new automated checks in the software that integrated automated quality assurance (QA) checks on the hourly data. Thus, the EPA believes that the data from 2002 and forward are of higher quality.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **21** of **763** 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 implementing large modifications are similar to the proposed standards for such units. In the proposal, we suggested that the standard should be based on when the modification is undertaken (i.e., before being subject to requirements under a CAA section 111(d) state plan or after being subject to such a plan). We also suggested that for units that undertake modifications prior to becoming subject to an approved CAA section 111(d) state plan, the standard should be its best historical performance plus an additional two percent reduction. In response to comments on the proposal, we are not finalizing separate standards that are dependent upon when the modification takes place, nor are we finalizing the proposed additional two percentage reduction. The EPA is not promulgating final standards of performance for, and is withdrawing the proposed standards for steam generating sources that make modifications resulting in an increase of hourly CO 2 emissions of less than or equal to 10 percent (see section XV of this preamble) . As we indicated in the proposal, the EPA has been 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 for GHG***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **22** of **763** emiss ions 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 sufficient information at this time, however, to anticipate the types of modifications , if any, that may result from these changes. In particular, we do not have sufficient information about the types of modifications , if any, that would result in increases in CO 2 emissions of 10 percent or less, and what the appropriate standard for such sources would be. Therefore, we conclude that it is prudent to delay issuing standards for sources that undertake small modifications (i.e., those resulting in an increase in CO 2 emissions of les s than or equal to 10 percent). For reconstructed steam generating units, the EPA is finalizing standards based on the performance of the most efficient generating technology for these types of units as the BSER (i.e., reconstructing the boiler if necessa ry to use steam with higher temperature and pressure, even if the boiler was not originally designed to do so ) . 11 The emission standard for these sources is 1,800 lb CO 2 /MWh - g for large sources , ( i.e. those with a heat input rating of greater than 2,000 MMBtu/h ) or 2,000 lb

11 Steam with higher temperature and pressure has more thermal energy that can be more efficiently converted to electrical energy.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **23** of **763** CO 2 /MWh - g for small sources ( i.e. , those with a heat input rating of 2,000 MMBtu/h or less ) . The difference in the standards for larger and smaller units is based on greater availability of higher pressure/temperature steam turbines (e.g., supercritical steam turbines) for larger units. The standards can also be met through other non -BSER options , such as natural gas co - firing. b. S tationary combustion turbines . This action also finalizes standards of performance for newly constructed and reconstructed stationary combustion turbines . In the January 2014 proposal for newly constructed EGUs , the EPA proposed that natural gas - fired stationary combustion turbine s (i.e., turbines combusting over 90 percent natural gas) would be subject to a standard of performance for CO 2 emissions if they are constructed for the purpose of supplying and actually annually supply to the grid ( 1) one - third or more of their potential electric output 12 and ( 2) more than 219,000 MWh , 13 based on a three - year rolling average . We refer to units that operat e above the electric sales thresholds as " base l oad units , " and we refer to units that operate below these thresholds as " non -base load units . "

12 We refer to thresholds related to an EGU's actual annual electrical sales (as a fraction of potential annual output ) a s "percentage electric sales criteria." 13 We refer to thresholds related to an EGU's actual annual electrical sales in megawatt
-hours as "total electric sales criteria."***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **24** of **763** In the January 2014 proposal for newly constructed combustion turbines, the EPA propose d standards for two subcategories of base load natural gas - fired stationary combustion turbine s . The proposed standard for small 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 greater than 850 MMBtu/h) was 1,000 lb CO 2 /MWh - g . The EPA did not propose standards for non -base load units . I n the June 2014 proposal for modified and reconstructed combustion turbines , the EPA solicited comment on alternative approaches for establishing applicability and subcategorization criteria , including (1) eliminating the “constructed for the purpose of supplying” qualif ier for the total electric sales and percentage electric sales criteri a , (2 ) eliminating the 219,000 MWh total electric s ales criterion altogether , ( 3) replacing the fixed percentage electric sales criterion with a variable percentage electric sales criterion (i.e., the sliding
- scale approach 14 ) , and ( 4) eliminating the proposed small and large subcategories for base load natural gas - fired combustion turbines . These proposed applicability requirements were

14 The sliding
- scale approach determines a unit
- specific percentage electric sales threshold equivalent to a unit’s net design efficiency (the maximum value is capped at 50 percent).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **25** of **763** intended to exclude combustion turbines that are used for the purpose of me eting peak power demand , as opposed to those that are used to meet base load power demand. In both proposal s , the EPA also solicited comment on a broad applicability approach that would include non -base load natural gas - fired units (primarily simple cycle combustion turbines) and multi
- fuel - fired units (primarily distillate oil
fired combustion turbines) in the general applicability of subpart TTTT . As part of the broad applicability approach, the EPA solicited comment on imposing “no emission standard” or establishing separate numerical limits for these two subcategories. In this action, the EPA is finalizing a variation of 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 public comments related to the proposed subcategories for small and large combustion turbines and our additional data analyses , we have determined that there is no need to set two s eparate standards for different size combustion turbines for base load natural gas - fired combustion turbines . The EPA has determined that all sizes of affected newly constructed and reconstructed stationary combustion turbines can achieve the final standards . For newly constructed and reconstructed base load natural gas - fired***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **26** of **763** stationary combustion turbines , the EPA is finalizing 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 addition, the EPA is finalizing the sliding
- scale approach for deriving the unit
specific, percentage electric sales threshold above which a combustion turbi ne 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 finalizing the combustion of clean fuels (natural gas with a small allowance for distillate oil) as the BSER with a corresponding heat input
based standard of 120 lb CO 2 /MMBtu . This standard of performance will apply to the vast majority of simple cycle combustion tu rbines. The EPA is finalizing a heat input
-based clean fuels standard because we have insufficient information at 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 reconstructed multi
fuel - fired stationary combustion turbines, the EPA is finalizing***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **27** of **763** an input
-based standard of 120 to 160 lb CO 2 /MMBtu based on the combustion of clean fuels as the BSER. 16 The EPA has similarly determined that it has insufficient information at this time to set a uniform output
-based standard for stationary combustion turbines that operate with significant quantities of a fuel other than natural gas. We are not promulgating final standards of performance for stationary combustion turbines that make modifications at this time . We are simultaneously withdrawing the proposed standards for modifications (see section XV of this preamble) . As we indicated in the proposal, sources from the power sector have notified the EPA of very few NSPS modifications, and we expect that there will be few NSPS modifications for CO 2 emissions as well. Moreover, our decision to eliminate the subcategories for small and large EGUs and set a single standard of 1,000 lb CO 2 /MWh
- g has raised questions as to whether smaller existing combustion turbines that undertake a modification can meet this standard. As a result , we have conclude d that it is prudent to delay issuing standards for s ources that undertake modifications until we can gather more information .

16 Combustion turbines co
- firing natural gas with other fuels shall determine fuel
-based site
- specific standards at the end of each operating month. The site
- specific standards depend on the amount of co - fired natural gas.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **28** of **763** A more detailed discussion of the final standards of performance, the applicability criteria, and the comments that influenced the final standards is provided in Sections VIII and IX of this preamble . 3. Costs and Benefits As explained in the regulatory impact analysis (RIA) for this final rule, available data

– including utility announcements and Energy Information Administration ( EIA ) modeling
- indicate that, even in the absence of this rule, (i) existing and anticipated economic conditions are such that few, if any, fossil fuel
- fired steam- generating EGUs will be built in the foreseeable future, and (ii) utilities and project developers are expected to choose new generation technologies (primarily NGCC) that would meet the final standards and renewable generating sources that are not affected by these final standards . These projections are consistent with utility announcements and EIA modeling that indicate that new units are like ly to be NGCC and that any coal - fired steam generating units built between now and 2030 would have CCS, even in the absence of this rule. 17 Therefore, based on the analysis presented in

17 The EPA ’s Integrated Planning Model (IPM) projects no new non
compliant coal (i.e., newly constructed coal
- fired plants that do not meet the final standard of performance) throughout the model horizon of 2030 (there is a small amount of new coal with CCS that is hardwired into the modelling, consistent with EIA***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **29** of **763** Chapter 4 of the RIA, the EPA projects that this final rule will
res ult in negligible CO 2 emission changes, quantified benefits, and costs by 2022 as a result of the performance standards for newly constructed EGUs. 18 However, as noted earlier, for a variety of reasons , some companies may consider coal
- fired steam generating units that the modeling does not anticipate. Thus, in Chapter 5 of the RIA, we also present an analysis of the project
- level costs 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 - fired unit without CCS. This analysis indicates that the quantified benefits of the standards of performance would exceed their costs under a range of assumptions . As explained in the RIA and further below, the EPA has been notified of few power sector NSPS modifications or reconstructions . Based on that experience , the EPA expects that few EGUs will trigger either the modification or the reconstruction provisions that we are finalizing in this action. 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. assumptions to represent units already under construction or under development). 18 Conditions in the analysis year of 2022 are represented by a model year of 2020.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **30** of **763** B. Does this action apply to me? The entities potentially affected by the standards are shown in Table 2 below. **Table 2. Potentially Affected Entities a**  **Category NAICS** 

**Code Examples of Potentially Affected**  **Entities** Industry 221112 Fossil fuel electric power generating units. Federal Government 221112 b Fossil fuel electric power generating units owned by the federal government. State/Local Government 221112 b Fossil fuel electric power generating units owned by municipalities. Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.

a Includes NAICS categories for source categories that own and operate electric power generating units (including boilers and stationary combined cycle combustion turbines). b Federal, state, or local government - owned and operated establishments are classif ied according to the activity in which they are engaged. This table is not intended to be exhaustive , but rather to provide a guide for readers regarding entities likely to be affected by this action. To determine whether your facility, company, business, organization, etc., would be regulated by this action, refer to Section III of this preamble for more information and examine the applicability criteria in 40 CFR***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **31** of **763** 60.1 (General Provisions) and 40 CFR 60.5508 40 of subpart TTTT (Standards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units) . If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions). C. Where can I get a copy of this document? In addition to being available in the docket, an electronic copy of this final action will also be available on the Worldwide Web (WWW). Following signature, a copy of this final action will be posted at the following address: http://www2.epa.gov/carbon -pollution
-standards. D. Judicial Review Under section 307(b)(1) of the CAA, judicial review of this final rule is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by [ **insert date 60**  **da ys after publication in federal register**  ]. Moreover, under section 307(b)(2) of the CAA, the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by EPA to enforce these requirements. Sec tion 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **32** of **763** public comment (including any public hearing) may be raised during judicial review.” This sect ion also provides a mechanism mandating the EPA to convene a proceeding for reconsideration “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the perio d for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration should submit a Petition for Reconsideration to the Office o f the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding **FOR FURTHER INFORMATION CONTACT** section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave., NW, Washington, DC 20460. E. How is th is preamble organiz ed ? This action presents the EPA’s final standards of performance for newly constructed, mo dified, and reconstructed fossil fuel
- fired electric utility steam generating units and newly constructed and reconstructed stationary combustion turbines. Section II provides background information on climate change impacts from GHG emissions, GHG emissions from fossil***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **33** of **763** fuel - fired EGUs, the utility power sector, the statutory and regulatory background relating to CAA section 111(b), EPA actions prior to this final action, and public comments regarding the proposed actions. Section III explains the EPA ’s authority to regulate CO 2 and EGUs, identifies affected EGUs , and describes the source categories. Section IV provides a summary of the final standards for newly constructed, modified, and reconstructed fossil fuel
- fired steam generating units. Sections V through VII present the rationale for the final standards for newly constructed, modified, and reconstructed steam generating units, respectively. Sections VIII and IX provide a summary of the final standards for stationary combustion turbines and present the rationale for the final standards for newly constructed and reconstructed combustion turbines , respectively . Section X provides a summary of other final requirements for newly constructed, modified, and reconstructed fossil fuel
- fired steam generating units and stationary combustion turbines. Section XI addresses the consistency of the respective BSER determinations in these rules and under the emission guidelines issued separately under CAA section 111(d). Interactions with other EPA programs and rule s are described in Section XI I . Projected impacts of the final action are then described in Section XII I , followed by a discussion of statutory and executive order reviews in Section XIV . Section XV addresses the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **34** of **763** withdrawal of the proposed standards for steam generating EGUs that make modifications resulting in an increase of hourly CO 2 emissions of less than or equal to 10 percent and the proposed standards for modified stationary combustion turbines. 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 - comments document located in the docket . **II. Background**  In this section , we discuss climate change impacts from GHG emissions, both on public health and public welfare. We also present information about GHG emissions from fossil fuel - fired EGUs and describe the utility power sector and its changing structure . We then summarize the statutory and regulatory background relevant to this final rulemaking. In addition, we provide background information on the EPA’s January 8, 2014 proposed carbon pollution standards for newly constructed fossil 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 this section with a general discussion of comments and stakeholder input that the EPA received prior t o issuing this final rulemaking. A. Climate Change Impacts from GHG Emissions***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **35** of **763** According to the National Research Council, “Emissions of CO 2 from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the evolution of Earth’s climate. Because CO 2 in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impacts, some of which could become very severe. Therefore, emission reduction choices made today matter in determini ng impacts experienced not just over the next few decades, but in the coming centuries and millennia.” 19 In 2009, based on a large body of robust and compelling scientific evidence, the EPA Administrator issued the Endangerment Finding under CAA section 20 2(a)(1). 20 In the Endangerment Finding, the Administrator found that the current, elevated concentrations of GHGs in the atmosphere

— already at levels unprecedented in human history

— may reasonably be anticipated to endanger public health and welfare of current and future generations in the United States. We summarize these adverse effects on public health and welfare briefly here. 1. Public Health Impacts Detailed in the 2009 Endangerment Finding

19 National Research Council, Climate Stabilization Targets, p.3. 20 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **36** of **763** Climate change caused by human emissions of GHGs threatens the health of Americans in multiple ways. By raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and 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 future without climate change, climate change is expected to increase 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 expected to cause more intense hurricanes and more frequent and intense storms and heavy precipitation, with impacts on other areas of public health, such as the potential for increased deaths, injuries, infe ctious and waterborne diseases, and stress
- related disorders. Children, the elderly, and the poor are among the most vulnerable to these climate
- related health effects. 2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding Climate change impa cts touch nearly every aspect of public welfare. Among the multiple threats caused by human emissions of GHGs, climate changes are expected to place large areas of the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **37** of **763** country at serious risk of reduced water supplies, increased water pollution, and increa sed occurrence of extreme events such as floods and droughts. Coastal areas are expected to face a multitude of increased risks, particularly from rising sea level and increases in the severity of storms. These communities face storm and flooding 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 include threats to social and ecosystem services. Climate change is expected to result in an increase in pea k electricity demand. Extreme weather from climate change threatens energy, transportation, and water resource infrastructure. Climate change may also exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous
communities, and is very likely to fundamentally rearrange U.S. ecosystems over the 21 st century. Though some benefits may balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture and forest productivity as temperature continues to rise. These impacts are global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. 3. New Scientific Assessments and Observations***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **38** of **763** Since the administrative record concerning the Endangerment Finding closed following the EPA’s 2010 Reconsideration Denial, the climate has continued to change, with new records being set for a number of climate indicators such as global average 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 understanding of the climate system and strengthen the case that GHGs endanger public health and welfare both for current and future generations. These assessments, from the Intergovernmental Panel on Climate Change (IPCC), the U.S. Global Change Research Program (USGCRP), and the National Research Council (NRC), include: IPCC’s 2012 Special Report on Managing the Risks of Extreme Even ts and Disasters to Advance Climate Change Adaptation (SREX) and the 2013
- 2014 Fifth Assessment Report (AR5), the USGCRP’s 2014 National Climate Assessment, Climate Change Impacts in the United States (NCA3), and the NRC’s 2010 Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean (Ocean Acidification), 2011 Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **39** of **763** Level Rise for the Coasts of California, Oregon, and 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 assessments in keeping with the same approach outlined in Section VIII.A of the 2009 Endangerment Finding, which was to rely primarily upon the major assessments by the USGCRP, the IPCC, and the NRC of the National Academies to provide the technical and scientific information to inform the Administrator’s judgment regarding the question of whether GHGs endanger public health and welfare. These assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change i ssues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review. The findings of the recent scientific assessments confirm and strengthen the conclusion that GHGs endanger public health, now and in the future. The NCA3 indicates that human health in the United States will be impacted by “increased extreme weather events, wildfire, decreased air quality, threats to mental health, and illnesses transmitted by food, water, and disease
carrie rs such as mosquitoes and ticks.” The most recent***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **40** of **763** assessments now have greater confidence that climate change will influence production of pollen that exacerbates asthma and other allergic respiratory diseases such as allergic rhinitis, as well as effects on conjunctivitis and dermatitis. Both the 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 allergens. The NCA3 also fi nds that climate change, in addition to chronic stresses such as extreme poverty, is negatively affecting indigenous peoples’ health in the United States through impacts such as reduced access to traditional foods, decreased water quality, and increasing exposure to health and safety hazards. The IPCC AR5 finds that climate change
- induced warming in the Arctic and resultant changes in environment (e.g., permafrost thaw, effects on traditional food sources) have significant impacts, observed now and projecte d, on the health and well -being of Arctic residents, especially indigenous peoples. Small, remote, predominantly
- indigenous communities are especially vulnerable given their “strong dependence on the environment for food, culture, and way of life; their po litical and economic marginalization; existing social, health, and poverty disparities; as well as their frequent close proximity***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **41** of **763** to exposed locations along ocean, lake, or river shorelines.” 21 In addition, increasing temperatures and loss of Arctic sea ice increases the risk of drowning for those engaged in traditional hunting and fishing. The NCA3 concludes that children’s unique physiology and developing bodies contribute to making them particularly vulnerable to climate change . Impacts on children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. The IPCC AR5 indicates that children are among those especially susceptible to most allergic diseases, as well
as health effects associated with heat waves, storms, and floods. The IPCC finds that additional health concerns may arise in low
- income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households. Both the NCA3 and IPCC AR5 conclude that climate change will increase health risks facing the elderly. Older people are at much higher risk of mortality during extreme heat events.
21 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects . Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, 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, Cambridge, p. 1581.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **42** of **763** Pre - existing health conditions also ma ke older adults susceptible to cardiac and respiratory impacts of air pollution and to more severe consequences from infectious and waterborne diseases. Limited mobility among older adults can also increase health risks associated with extreme weather and floods. The new assessments also confirm and strengthen the conclusion that GHGs endanger public welfare, and emphasize the urgency of reducing GHG emissions due to their projections that show GHG concentrations climbing to ever
- increasing levels in the ab sence 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 experienced for more than 30 million ye ars. 22 In fact, that assessment stated that “the magnitude and rate of the present greenhouse gas increase place the climate system in what could be one of the most severe increases in radiative forcing of the global climate system in Earth history.” 23 Becau se of these unprecedented changes, several assessments state that we may be approaching critical, poorly understood thresholds . As stated in the assessment , “As Earth continues to warm, it may be approaching a critical climate

22 National Research Council, Understanding Earth’s Deep Past , p. 1. 23 Id . , p.138.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **43** of **763** threshold beyond which rapid and potentially permanent

— at least on a human timescale

— changes not anticipated by climate models tuned to modern conditions may occur.” The NRC Abrupt Impacts report analyzed abrupt climate change in the physical climate system and abrupt impacts of ongoing changes that, when thresholds are crossed, can cause abrupt impacts for society and ecosystems. The report considered destabilization of the West Antarctic Ice Sheet (which could cause 3
- 4 m of potent ial sea level rise) as an abrupt climate impact with unknown but probably low probability of occurring this century. The report categorized a decrease in ocean oxygen content (with attendant threats to aerobic marine life); increase in intensity, frequency, and duration of heat waves; and increase in frequency and intensity of extreme precipitation events (droughts, floods, hurricanes, and major storms) as climate impacts with moderate risk of an abrupt change within this century. The NRC Abrupt Impacts report also analyzed the threat of rapid state changes in ecosystems and species extinction s as example s of irreversible impact s that are expected to be exacerbated by climate change. Species at most risk include those whose migration potential is limited, whether because they live on mountaintops or fragmented habitats with barriers to movement, or because climatic conditions are changing more rapidly than the species can move or adapt. While the NRC determined that it***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **44** of **763** is not presently possible to place exact probabilities on the added contribution of climate change to extinction, they did find that there was substantial risk that impacts from climate change could, within a few decades, drop the populations in many species below sustainable levels , thereby committing the species to extinction. Species within tropical and subtropical rainforests such as the Amazon and species living in coral reef ecosystems were identified by the NRC as being particularly vulnerable to extinction over the next 30 to 80 years, as were species in high latitude and high elevation regions. Moreover, due to the time lags inherent in the Earth’s climate, the NRC Climate Stabilization Targets assessment notes that the full warming from any given concentration of CO 2 reached will not be fully realized for several centuries, underscoring that emission activities today carry with them climate commitments far into the future. Future temperature changes will depend on what emission path the world follows. In its high emission scenario, the IPCC AR5 projects that average global temperatures by the end of the century will likely be 2.6 degrees Cel s ius ( °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 noticeably***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **45** of **763** less future warming beyond mid
- century, and therefore less impact to public health and welfare. While rainfall may only see small globally and annually averaged changes, there are expected to be substantial shifts in where and when that precipitation falls. According to the NCA3, regions closer to the poles will see more precipitation, while the dry subtropics are expected to expand (colloquially, this has been summarized as wet areas getting wetter and dry regions getting drier). In particular, the NCA3 notes that the west ern U.S., and especially the Southwest, is expected to become drier. This projection is consistent with the recent observed drought trend in the West. At the time of publication of the NCA, even before the last 2 years of extreme drought in California, tre e ring data was already indicating that the region might be experiencing its driest period in 800 years. Similarly, the NCA3 projects that heavy downpours are expected to increase in many regions, with precipitation events in general becoming less frequent but more intense. This trend has already been observed in regions such as the Midwest, Northeast, and upper Great Plains. Meanwhile, the NRC Climate Stabilization Targets assessment found that the area burned by wildfire is expected to grow by 2 to 4 time s for 1 °C (1.8 °F) of warming. For 3 °C of warming, the assessment found that 9 out of 10 summers would be warmer than all but the 5 percent of warmest summers today,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **46** of **763** leading to increased frequency, duration, and intensity of heat waves. Extrapolations by the NCA also indicate that Arctic sea ice in summer may essentially disappear by mid
- century. 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 NCA3, and multiple NRC assessments have projected future rates 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 o f 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 ) global average sea - level rise by 2100,” 24 and the NRC Climate Stabilization Targets assessment states that an increase of 3 °C will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 feet) by 2100. These assessments continue to recognize that there is uncertainty inherent in accounting for ice sheet processes. Additionally, local sea level rise can diffe r from
24 NRC, 2011: National Security Implications of Climate Change for U.S. Naval Forces . The National Academies Press, p . 28.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **47** of **763** the global total depending on various factors . The east coast of the U.S. in particular is expected to see higher rates of sea level rise than the global average. For comparison, the NCA3 states that “five million Americans and hundreds of bill ions of dollars of property are located in areas that are less than four feet above the local high
- tide level,” and the NCA3 finds that “[c]oastal infrastructure, including roads, rail lines, energy infrastructure, airports, port facilities, and military bases, are increasingly at risk from sea level rise and damaging storm surges.” 25 Also, because of the inertia of the oceans, sea level rise will continue for centuries after GHG concentrations have stabilized (though more slowly than it would have otherwise ). Additionally, there is a threshold temperature above which the Greenland ice sheet will be committed to inevitable melting . According to the NCA, some recent research has suggested 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 the United States and have a greater impact on certain populations, such as indigenous peoples and the poor. The NCA3 finds that climate
25 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary 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
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– Do Not Cite, Quote or Release During Review *** Page **48** of **763** change impacts such as the rapid pace of temperature 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 Alaska, critical infrastructure and traditional livelihoods are threatened by climate change and, “[i]n parts of Alaska, Louisiana, the Pacific Islands, and other coastal locations, climate change impacts (through erosion and inundati on) are so severe that some communities are already relocating from historical homelands to which their traditions and cultural identities are tied.” 26 The IPCC AR5 notes, “Climate
- related hazards exacerbate other stressors, often with negative outcomes for livelihoods, especially for people living in poverty (high confidence). 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 example, in creased food prices and food insecurity.” 27

26 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, p. 17. 27 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectora l 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.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **49** of **763** CO 2 in particular has unique impacts on ocean ecosystems. The NRC Climate Stabilization Targets assessment found that coral bleaching will increase due both to warming and ocean acidification. Ocean surface water s have already become 30 percent more acidic over the past 250 years due to absorption of CO 2 from the atmosphere. According to the NCA3, this acidification will reduce the ability of organisms such as corals, krill, oysters, clams, and crabs to survive, grow, and reproduce. The NRC Understanding Earth's Deep Past assessment notes that four of the five major coral reef crises of the 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 specifi cally highlighted similarities between the projections for future acidification and warming and the extinction at the end of the Permian which resulted in the loss of an estimated 90 percent of known species. Similarly, the NRC Ocean Acidification assessment finds that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic CO 2 emissions; the rate of change exceeds any known to have occurred for at least the past hundreds of
Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, p. 796.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **50** of **763** thousands of years.” 28 The assessment notes that the full range of consequences is still unknown, but the risks “threaten coral reefs, fisheries, protected species, and other natural resources of value to society.” 29 Events outside the United States, as also pointed out in the 2009 Endangerment Finding, will also have relevant consequences. The NRC Climate and Social Stress assessment concluded that it is prudent to expect that some climate events “will produce consequences that exceed the capacity of the affected societies o r global systems to manage and that have global security implications serious enough to compel international response.” The NRC National Security Implications assessment recommends preparing for increased needs for humanitarian aid; responding to the effec ts of climate change in geopolitical hotspots, including possible mass migrations; and 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 States. According to the IPCC AR5 and the NCA3, there are a number of
28 NRC, 2010: Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean . The National Academies Press, p. 5. 29 Ibid.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **51** of **763** climate
- related changes that have been observed recently, and these changes are projected to accelerate in the future. The planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is extremely likely (>95 percent probability) that human influence was the dominant cause of the observed warming since 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 Hemisphere, the last 30 years were likely the warmest 30
- year period of the last 1400 years. U.S. average temperatures have similarly increased by 1. 3 to 1.9 ° F since 1895, with most of that increase occurring since 1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 2010. Contributing to this rise was the warming of the oceans and melting of land ice. It is likely that 275 gigatons per year of ice have melted from land glaciers (not including ice sheets) since 1993, and that the rate of loss of ice from the Greenland and Antarctic ice sheets has increased substantially in recent years, to 215 gigatons per year and 147 gigatons per year respectively , since 2002. For context, 360 gigatons of ice melt is sufficient to cause global sea levels to rise 1 mm. Annual mean Arctic sea ice has been declining at 3.5 to 4.1 percent per decade, and Northern Hemisphere snow cover extent has decrea sed at about 1.6 percent per decade for March and 11.7 percent per decade for June. Permafrost temperatures***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **52** of **763** 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 i ncreased in the Northern Hemisphere. The NCA3 states that the increases in the severity or frequency 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 systems. In addition to the changes documented in the assessment literature, there have been other climate milestones of note. In 2009, the year of the Endangerment Finding, the average
con centration of CO 2 as measured on top of Mauna Loa was 387 parts per million, far above preindustrial concentrations of about 280 parts per million. 30 The average concentration in 2013, the last full year before this rule was proposed, was 396 parts per mill ion. The average concentration in 2014 was 399 parts per million. And the monthly concentration in April of 2014 was 401 parts per million, the first time a monthly average has exceeded 400 parts per million since record keeping began at Mauna Loa in 1958, and for at least the past 800,000 years. 31 Arctic sea ice has continued to decline, with September of 2012 marking a new

30 ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt 31 http://www.esrl.noaa.gov/gmd/ccgg/trends/ .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **53** of **763** record low in terms of Arctic sea ice extent, 40 percent below the 1979
- 2000 median. 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. 32 And 2014 was the warmest year globally in the modern global surface temperature record, going back to 1880; this now means 19 of the 20 warmest years have occurred in the past 20 years, and except for 1998, the ten warmest years on record have occurred since 2002. 33 The first months of 2015 have also been some of the warmest on record. These assessments and observed changes make it clear that reducing emissions of GHGs across the globe is necessary in order to avoid the worst impacts of climate change, and underscore the urgency of reducing emissions now. The NRC Committee on America’s Climate Choices liste d a number of reasons “why it is imprudent to delay actions that at least begin the process of substantially reducing emissions.” 34 For example:

 The faster emissions are reduced, the lower the risks posed by climate change. Delays in reducing emissions
32 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1
- S238. 33 http://www. ncdc.noaa.gov/sotc/global/2014/13 34 NRC, 2011: America’s Climate Choices , The National Academies Press.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **54** of **763** could commit the planet to a wide range of adverse impacts, especially if the sensitivity of the climate to greenhouse gases is on the higher end of the estimated range.

 Waiting for unacceptable impacts to occur before taking action is imprudent because the effects of greenhouse gas emissions do not fully manifest themselves for decades and, once manifest, many of these changes will persist for hundreds or even thousands of years.

 In the committee’s judgment, the risks associated with doing business as u sual are a much greater concern than the risks associated with engaging in strong response efforts. 4. Observed and Projected U.S. Regional Changes The NCA3 assessed the climate impacts in eight regions of the United States, noting that changes in physic al climate parameters such as temperatures, precipitation, and sea ice retreat were already having impacts on forests, water supplies, ecosystems, flooding, heat waves, and air quality. Moreover, the NCA3 found that future warming is projected to be much l arger than recent observed variations in temperature, with precipitation likely to increase in the northern states, decrease in the southern states, and with the heaviest precipitation events projected to increase everywhere. In the Northeast, temperature s increased almost 2 °F from 1895 to 2011, precipitation increased by about 5 inches (10 percent ), and sea level rise of about a foot has led to an increase in coastal flooding. The 70 percent increase in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **55** of **763** amount of rainfall falling in the 1 percent of the most intense events is a larger increase in extreme precipitation than experienced in any other U . S . region. In the future, if emissions continue increasing, the Northeast is expected to experience 4.5 to 10 °F of warming by the 2080s. This will l ead to more heat waves, coastal and river flooding, and intense precipitation events. The southern portion of the region is projected to see 60 additional days per year above 90 °F by mid

- century. Sea levels in the Northeast are expected to increase faster than the global average because of subsidence, and changing ocean currents may further increase the rate of sea level rise. Specific vulnerabilities highlighted by the NCA include large urban populations particularly vulnerable to climate
- related heat waves and poor air quality episodes, prevalence of climate sensitive vector
-borne diseases like Lyme and West Nile Virus, usage of combined sewer systems that may lead to untreated water being released into local water bodies after climate
- related heavy precipitation events, and 1.6 million people living within the 100
- year coastal flood zone who are expected to experience more frequent floods due to sea level rise and tropical
- storm induced storm
- surge. The NCA also highlighted infrastructure vulnerable to inundation in coastal metropolitan areas, potential agricultural impacts from increased rain in the spring delaying planting or damaging crops***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **5 6**  of **763** or increased heat in the summer leading to decreased 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 , fo llowed by a cool period , and temperatures then increased again from 1970 to the present by an average of 2 °F. There have been increasing numbers of days above 95 °F and nights above 75 °F, and decreasing numbers of extremely cold days since 1970. Daily and five
- day rainfall intensities have also increased, and summers have been either increasingly dry or extremely wet. Louisiana has already lost 1,880 square miles of land in the last 80 years due to sea level rise and other contributing factors. The Southe ast is exceptionally vulnerable to sea level rise, extreme heat events, hurricanes, and decreased 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 exacerbated groundlevel ozone in urban areas. Although projected warming for some parts of the region by the year 2100 is generally smaller than for other regions of the United States, projected warming for interior states of the region is larger than coastal regions by***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **57** of **763** 1 °F to 2 °F. Projections further suggest that there will be fewer tropical storms globally , but that they will be more intense, with more Category 4 and 5 storms. The NCA identified New Orleans, Miami, Tampa, Charleston, and Virginia Beach as being specific cities that are at risk due to sea level rise, with homes and infrastructure increasingly prone to flooding. Additional impacts of sea level rise are expected for coastal highways, wetlands, fresh water supplies , and energy infrastructure . In the Northwest, temperatures increased by about 1.3 oF between 1895 and 2011. A small average increase in precipitation was observed over this time period. However, warming temperatures have caused increased rainfall relative to snowfall, which has altered water availability from snowpack across parts of the region. Snowpack in the Northwest is an important freshwater source for the region. More precipitation falling as rain instead of snow has reduced the snowpack, and warmer springs have corresponded to earlier snowpack melting and reduced streamflows during summer months. Drier conditions have increased the extent of wildfires in the region. Average annual temperatures are projected to increase by 3.3 oF to 9.7 oF by the end of the century (depending on future global GHG emissions), with the greatest warming expected during the summer. Continued increases in global GHG emissions are***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **58** of **763** projected to result in up to a 30 percent decrease in summer precipitation. Earlier snowpack melt and lower summer stream flows are expected by the end of the century and will affect drinking water supplies, agriculture, ecosystems, and hydropower production. Warmer waters are expected to increase disease and mortality in important fish species, including Chinook and sockeye salmon. Ocean acidification also threatens species su ch as oysters, with the Northwest coastal waters already being some of the most acidified worldwide due to coastal upwelling and other local factors. Forest pests are expected to spread and wildfires to burn larger areas. Other high
- elevation ecosystems
are projected to be lost because they can no longer survive the climatic conditions. Low lying coastal areas, including the cities of Seattle and Olympia, will experience heightened risks of sea level rise, erosion, seawater inundation and damage to infrastructure and coastal ecosystems. In Alaska, temperatures have changed faster than anywhere else in the United States. Annual temperatures increased by about 3 °F in the past 60 years. Warming in the winter has been even greater, rising by an average of 6 °F. Arctic sea ice is thinning and shrinking in area, with the summer minimum ice extent now covering only half the area it did when satellite records began in 1979. Glaciers in Alaska are melting at some of the fastest rates on Earth. Permafrost soils are a lso warming***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **59** of **763** and beginning to thaw. Drier conditions have contributed to more large wildfires in the last 10 years than in any previous decade since the 1940s, when recordkeeping began. Climate change impacts are harming the health, safety , and livelihoods 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 state. These increases will exacerbate ongoing a rctic sea ice loss, glacial melt, pe rmafrost thaw and increased wildfire, and threaten humans, ecosystems, and infrastructure. Precipitation is expected to increase to varying degrees across the state . However , warmer air temperatures and a longer growing season are expected to resu lt in drier conditions. Native Alaskans are expected to experience declines in economically, nutritionally, and culturally important wildlife and plant species. Health threats will also increase, including loss of clean water, saltwater intrusion, sewage c ontamination from thawing permafrost, and northward exten sion of diseases. Wildfires will increasingly pose threats to human health as a result of smoke and direct contact. Areas underlain by ice
- rich permafrost across the state are likely to experience ground subsidence and extensive damage to infrastructure as the permafrost thaws.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **60** of **763** Important ecosystems will continue to be affected. Surface waters and wetlands that are drying provide breeding habitat for millions of waterfowl and shorebirds that winter in the lower 48 states. Warmer ocean temperatures, acidification, and declining sea ice will contribute to changes in the location and availability o f commercially and culturally important marine fish. In the Southwest, temperatures are now about 2 °F higher than the past century, and are already the warmest that region has experienced in at least 600 years. The NCA notes that there is evidence that climate change - induced warming on top of recent drought has influenced tree mortality, wildfire frequency and area, and forest insect outbreaks. Sea levels have risen about 7 or 8 inches in this region, contributing to inundation of Highway 101 and backup of seawater into sewage systems in the San Francisco area. Projections indicate that the Southwest will warm an additional 5.5 to 9.5 °F over the next century if emissions continue to increase. Winter snowpack in the Southwest is projected to decline (consistent with the record lows from this past winter), reducing the reliability of surface water supplies for c ities, agriculture, cooling for power plants, and ecosystems. Sea level rise along the California coast will worsen coastal erosion, increase flooding risk for coastal***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **61** of **763** highways, bridges, and low
- lying airports, pose a threat to groundwater supplies in coas tal cities such as Los Angeles, and increase vulnerability to floods for hundreds of thousands of residents in coastal areas. Climate change will also have impacts on the high
-value specialty crops grown in the region as a drier climate will increase demands for irrigation, more frequent heat waves will reduce yields, and decreased winter chills may impair fruit and nut production for trees in California. Increased drought, higher temperatures, and bark beetle outbreaks are likely to contribute to continued increases in wildfires. The highly urbanized population of the Southwest is vulnerable to heat waves and water supply disrupt ions, which can be exacerbated in cases where high use of air conditioning triggers energy system failures. The rate of warming in the Midwest has markedly accelerated over the past few decades. Temperatures rose by more than 1.5 °F from 1900 to 2010, but between 1980 and 2010 , the rate of warming was three times faster than from 1900 through 2010. Precipitation generally increased over the last century, with much of the increase driven by intensification of the heaviest rainfalls. Several types of extreme weather events in the Midwest (e.g., heat waves and flooding) have already increased in frequency and/or intensity due to climate change.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **62** of **763** In the future, if emissions continue increasing, the Midwest is expected to experience 5.6 to 8.5 °F of warming by the 2080s, leading to more heat waves. Though projections of changes in total precipitation vary across the regions, more precipitation is expected to fall in the form of heavy downpours across the entire region, leading to an increase in flooding. Specific vulnerabilities highlighted by the NCA include long
term decreases in agricultural productivity, changes in the composition of the region’s forests, increased public health threats from heat waves and degraded air and water quality, negative impacts on transportation and other infrastructure associated with extreme rainfall events and flooding, and risks to the Great Lakes including shifts in invasive species, increases in harmful algal blooms, and declining beach health. High temperatures (more than 100 °F in the Southern Plain s and more than 95 °F in the Northern Plains) are projected to occur much more frequently by mid
- century. Increases in extreme heat will increase heat stress for residents, energy demand for air conditioning, and water losses. North Dakota’s increase in annual temperatures over the past 130 years is the fastest in the contiguous U.S., mainly driven by warming winters. Specific vulnerabilities highlighted by the NCA include increased demand for water and energy, changes to crop - growth cycles and agricultural practices, and negative impacts on local plant and***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **63** of **763** animal species from habitat fragmentation, wildfires, 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 frequent 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 patterns, changing frequencies and intensities of storms and drought, decreasing baseflow in streams, rising sea levels, and changing ocean chemistry will affect ecosystems on land and in the oceans, as well as local communities, livelihoods, and cultures. Low islands a re particularly at risk. Rising sea levels, coupled with high water levels caused by tropical and extra
- tropical storms, will incrementally increase coastal flooding and erosion, damaging coastal ecosystems, infrastructure, and agriculture, and negatively affecting tourism. Ocean temperatures in the Pacific region exhibit strong year - to - year and decadal fluctuations, but since the 1950s, they have exhibited a warming trend, with temperatures from 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 will become more***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **64** of **763** limited on many islands. Saltwater intrusion associated wi th sea level rise will reduce the quantity and quality of freshwater in coastal aquifers, especially on low islands. In areas where precipitation does not increase, freshwater supplies will be adversely affected as air temperature rises. Warmer oceans are leading to increased coral bleaching events and disease outbreaks in coral reefs, as well as changed distribution patterns of tuna fisheries. Ocean acidification will reduce coral growth and health. Warming and acidification, combined with existing stresse s, will strongly affect coral
- reef fish communities. For Hawaii and the Pacific islands, future sea surface temperatures are projected to increase 2.3 °F by 2055 and 4.7 °F by 2090 under a scenario that assumes continued 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 further increase by 37 percent to 50 percent from present levels by 2100.The NCA also discussed impacts that occur along the coasts and in the oceans adjacent to many regions, and noted that other impacts occur across regions and landscapes in ways that do not follow political boundaries. B. GHG Emissions from Fossil Fuel
-fired EGUs***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **65** of **763** Fossil fuel
- fired EGUs are by far the largest emitters of GHGs among stationary sources in the U.S., primarily in the form of CO 2 . Among fossil fuel
- fired EGUs, coal
- fired units are by far the largest emitters. This section describes the amounts of these emissions and places these amounts in the context of the U.S. Inventory of Greenhouse Gas Emissions and Sinks 35 (the U.S. GHG Invent ory). The EPA implements a separate program under 40 CFR part 98 called the Greenhouse Gas Reporting Program36 (GHGRP) that requires emitting facilities that emit over certain threshold amounts of GHGs to report their emissions to the EPA annually. Using data from the GHGRP, this section also places emissions from fossil fuel
- fired EGUs in the context of the total 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 includes recent trends, is organized by industrial sector . It provides

35 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

– 2013”, Report EPA 430
-R- 15
- 004, United States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 36 U.S. EPA Greenhouse Gas Reporting Program Dataset, see http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **66** of **763** the information in Table 3 below, which presents total U.S. anthropogenic emissions and sinks 37 of GHGs, including CO 2 emissions, for the years 1990, 2005 and 2013. **Table 3. U.S. GHG Emissions and Sinks by Sector (million metric tons carbon dioxide equivalent (MMT**  **CO 2** **e ))**  **38 ,**  **39**
**SECTOR 1990**  **2005 2013**  Energy 40 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

37 Sinks are a physical unit or process that stores GHGs, such as forests or underground or deep sea reservoirs of CO 2 . 38 From Table ES - 4 of “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

– 2013”, Report EPA 430
-R- 15
- 004 , United States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 39 1 metric ton (tonne) is equivalent to 1,000 kilograms (kg) and is equivalent to 1.1023 short tons or 2,204.62 pounds (lb). 40 The energy sector includes all greenhouse gases resulting from stationary and mobile energy activities including fuel combustion and fugitive fuel emissions.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **67** of **763** Total fossil energy
- related CO 2 emissions (including both stationary and mobile sources) are the largest contributor to total U.S. GHG emissions, representing 77.3 percent of total 2013 GHG emissions. 41 In 2013, fossil fuel combustion by the utility power sector

– entities that burn fossil fuel and whose primary business is the generation of electricity

– accounted for 38.3 percent of all energy
- related CO 2 emissions. 42 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 Electricity from Combustion of Fossil Fuels (MMT**  **CO 2**  **) 43** 

41 From Table ES - 2 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

– 201 3 ”, Report EPA 430
-R- 15
- 004, United States Environmental Protection Agency, April 15, 2015 . http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 42 From Table 3
- 1 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

– 201 3 ”, Report EPA 430
-R- 15
- 004, United States Environmental Protection Agency, April 15, 2015 . http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 43 From Table 3
- 5 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

– 201 3 ”, Report EPA 430
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- 004, United States Envi ronmental Protection Agency, April 15 2015 . http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. **GHG EMISSIONS 1990**  **2005 2013**  Total CO 2 from fossil fuel
fired 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***EO 12866_Review
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In addition to preparing the official U.S. GHG Inventory to present comprehensive total U.S. GHG emissions and comply with commitments under the UNFCCC, the EPA collects detailed GHG emissions data from the largest emitting facilities in the U.S. through i ts GHGRP. Data collected by the GHGRP from large stationary sources in the industrial sector show that the utility power sector emits far greater CO 2 emissions than any other industrial sector. Table 5 below presents total GHG emissions in 2013 for the largest emitting industrial sectors as reported to the GHGRP. As shown in Table 4 and Table 5, respectively, CO 2 emissions from fossil fuel
- fired EGUs are nearly three times as large as the total reported GHG emissions from the next ten largest emitting industrial sectors in the GHGRP database combined . **Table 5. Direct GHG Emissions Reported to GHGRP by Largest Emitting Industrial Sectors (MMT**  **CO 2** **e) 44** 

44 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 18, 2014 . http://ghgdata.epa.gov/ghgp/main.do . - from petroleum 97.5 97.9 22.4

**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***EO 12866_Review
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It should be noted that the discussion above concerned 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. 45 C. The Utility Power Sector 1. Modern Electric System Trends The EPA includes a background discussion of the electricity system in the Clean Power Plan (CPP) rulemaking, which is the companion rulemaking to this rule that promulgates emission guidelines for states to use in regulating emissions of CO 2 from existing fossil fuel
- fired EGUs. Readers are referred to that rulemaking. The following discussion of electricity sector trends is of particular relevance for this rulemaking. The electricity sector is undergoing a period of intense change. Fossil fuels

– such as coal, natural gas, and oil

– have historically provided a large percentage of electricity in the U.S., with smaller amounts being provided by other types of generation , including nuclear and renewables such as wind,
45 These figures are based on data for EGUs in the Acid Rain Program plus additional ones that report to the EPA under the Regional Greenhouse Gas Initiative. 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
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– Do Not Cite, Quote or Release During Review *** Page **70** of **763** solar, and hydroelectric power. Coal has historically provided the largest percentage of fossil
- fuel generation. 46 In recent years, the nation has seen a sizeable increase in renewable generation such as wind and solar, as well as a shift from coal to natural gas. 47 In 2013, fossil fuels supplied 67 percent of U.S. electricity, but renewables made up 38 percent of the new generation capacity (over 5 GW out of 13.5 GW). 48 From 2007 to 2014, use of lower
- and zero - carbon energy sources has grown, while other major energy sources such as coal and oil have experienced declines. Renewable electricity generation, including from large hydro
- electric projects, grew from 8 percent to 13 percent over that time period. 49 Between 2000 and

46 U.S. Energy Information Administration, “Table 7.2b Electricity Net Generation: Electric Power Se ctor” data from April 2014 Monthly Energy Review, release data April 25, 2014, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 47 U.S. Energy Information Administration, “Table 7.2b Electricity Net Generation: Electric Power Sector” data from April 2014 Monthly Energy Review, release data April 25, 2014, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 48 Based on Table 6.3 (New Utility Scale Generating Units by Operating Company, Plant, Month, and Year) of the U.S. Energy Information Administration (EIA) Electric Power Monthly, data for December 2013, for the following renewable energy sources: solar, wind, hydro, geothermal, landfill gas, and biomass. Available at: http:// www.eia.gov/electricity/monthly/epm

_table

_grapher.cfm?t=epmt

_6

_0 3. 49 Bloomberg New Energy Finance and the Business Council for Sustainable Energy , 2015 Factbook: Sustainable Energy in America , at 16 (2015), available at***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **71** of **763** 2013, approximately 90 percent of new power generation capacity built in the U.S. has come in the form of natural gas or renewable energy facilities. 50 In 2015, the U.S. Energy Information Administration (EIA) projected the need for 28.4 GW of additional ba se load or intermediate load generation capacity through 2020, with approximately 0.7 GW of new coal
- fired capacity, 5.5 GW of new nuclear capacity, and 14.2 GW of new NGCC capacity already in development. 51 The change in the resource mix has accelerate d in recent years, but wind, solar, other renewables, and energy
- efficiency resources have been reliably participating in the electric sector for a number of years. This rapid development of non
fossil fuel resources is occurring as much of the existing power generation fleet in the U.S. is aging and in need of modernization and replacement. 52 For example, the average age of

http://www.bcse.org/ images/2015%20Sustainable%20Energy%20in%20Am erica%20 Factbook.pdf. 50 Energy Information Administration, Electricity: Form EIA
- 860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/. 51 EIA, Annual Energy Outlook for 2015 with Projections to 2040 , Final Release, available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015). The AEO numbers include projects that are under development and model
-projected nuclear, coal, and NGCC projects. 52 Quadrennial Energy Review, http://energy.gov/epsa/quadrennial
energy- review
- qer***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **72** of **763** U.S. coal steam units in 2015 is 45 years . 53 In its 2013 Report Card for America’s Infrastructure , the American Society for Civil Engineers noted that “America relies on an aging electrical grid and pipeline distribution systems, some of which originated in the 1880s. ” 54 While there has been an increased investment in electric transmission infrastructure since 2005, the report also found that “ongoing permitting issues, weather events, and limited maintenance have contributed to an increasing number of failures and power interruptions.” 55 However, innovative technologies have increasingly entered the electric energy space, helping to provide new answers to how to meet the electricity needs of the nation. These new technologies can enable the nation to answer not just questi ons as to how to reliably meet electricity demand, but also how to meet electricity demand reliably and cost
- effectively 56 with the lowest possible emissions and the greatest efficiency.

53 We cal culated the average age of coal steam units based on the NEEDS inventory, and included units with planned retirements in 2015
- 2016. See http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx. 54 American Society for Civil Engineers, 2013 Report Card for America’s Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/. 55 American Society for Civil Engineers, 2013 Report Card for America’s Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/. 56 Business Council for Sustainable Energy Comments in Docket Id. No. EPA- HQ - OAR- 2013
- 0602 at 2 (Nov. 19 , 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **73** of **763** Natural gas has a long history of meeting electricity demand in the U.S. with a rapidly growing role as domestic supplies of natural gas have dramatically increased. Natural gas net generation increased by approximately 36 percent between 2004 and 2014. 57 In 2014, natural gas accounted for approximately 27 percent of net generation. 58 The EIA projects that this demand growth will continue , with its Annual Energy Outlook 2015 (AEO 2015) reference case forecasting that natural gas will produce 31 percent of U.S. electric generation in 2040. 59 Renewable sources of electric gene ration also have a history of meeting electricity demand in the U.S. and are expected to have an increasing role going forward. A series of energy crises provided the impetus for renewable energy development in the early 1970s. The OPEC oil embargo in 1973 and oil crisis of 1979 caused oil price spikes, more frequent energy shortages, and significantly affected the national and global
57 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_grapher.cfm?t=e pmt_1_1. 58 Id. 59 The AEO 2015 Reference case projection is a bu siness
- as - usual trend estimate, given known technology and technological and demographic trends. EIA explores the impacts of a lternative assumptions in other cases with different macroeconomic growth rates, world oil prices, and resource assumptions. U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 20 40 , at 24
- 25 (2015), available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **74** of **763** economy. In 1978, partly in response to fuel security concerns, Congress passed the Public Utilities Regulatory Policies Act (PURPA) which required local electric utilities to buy power from qualifying facilities (QFs). 60 QFs were either cogeneration facilities 61 or small generation resources that use renewables such as wind, solar, biomass, geothermal, or hydroelectric power
as their primary fuels. 62 Through PURPA, Congress supported the development of more renewable energy generation in the U.S. States have taken a significant lead in requiring the development of renewable resources. In particular, a number of states have adopte d renewable portfolio standards (RPS). As of 2013, 29 states and the District of Columbia have enforceable RPS or similar laws. 63 In its AEO 2015 Reference case, the EIA found that renewable energy will account for 38 percent of the overall growth in electr icity generation from 2013 to 2040. 64 The AEO 2015 Reference case forecasts that the renewables share of

60 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220
- 221 (2d ed. 2010). 61 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). 62 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220
- 221 (2d ed. 2010). 63 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2014 with Projections to 2040 , at LR- 5 (2014). 64 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at E - 12(2015).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **75** of **763** U.S. electricity generation will grow from 13 percent in 2013 to 18 percent in 2040. 65 Price pressures caused by oil embargoes in the 1970s also brought the issues of conservation and energy efficiency to the forefront of U.S. energy policy. 66 This trend continued in the early 1990s. Some state regulatory commissions and utilities supported energy efficiency through least
- cost planning, with the National Association of Regulatory Utility Commissioners (NARUC) “adopting a resolution that called for the utility’s least cost plan to be the utility’s most profitable plan.” 67 Energy efficiency has been utilized to meet energy demand to

65 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at 24
- 25(2015). 66 Edison Electric Institute, Making a Business of Energy Efficiency: Sustainable Business Models for Utilities , at 1 (2007). Congress passed legislation in the 1970s that jumpstarted energy efficiency in the U.S. For example, President Ford signed the Energy Policy and Conservation Act (EPCA) of 1975

– the first law on the issue. EPCA authorized the Federal Energy Administration (FEA) to “develop energy conservation contingency plans, established vehicle fuel economy standards, and authorized the creation of efficiency 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/Media%20browse r/ee_commission_history_report_2
- 1
- 13.pdf. 67 Edison Electric Institute, Making a Business of Energy Efficiency: Sustainable Business Models for Utilities , at 1 (2007), available at http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation /Documents/Making_Business_Energy_Efficiency.pdf .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **76** of **763** varying levels since that time. As of April 2014, 25 states 68 have “enacted long- term (3+ years), binding energy savi ngs targets, or energy efficiency resource standards (EERS).” 69 Funding for energy efficiency programs has grown rapidly in recent years, with budgets for electric efficiency programs totaling $5.9 billion in 2012. 70 Advancements and innovation in power se ctor technologies provide the opportunity to address CO 2 emission levels at affected power plants while at the same time improving the overall power system in the U.S. by lowering the carbon intensity of power generation, and ensuring a reliable supply of power at a reasonable cost. 2. Fossil Fuel
- F ired EGUs Regulated by This Action, Generally Natural gas - fired EGUs typically use one of two technologies: NGCC or simple cycle combustion turbines. NGCC

68 Ame rican Council for an Energy
-Efficient Economy, State Energy Efficiency Resource Standards (EERS) (2014), available at http://aceee.org/files/pdf/policy
-brief/eers
- 04
- 2014.pdf. ACEEE did not include Indiana (EERS eliminated), Delaware (EERS pending), Flori da (programs funded at levels far below what is necessary to meet targets), Utah, or Virginia (voluntary standards) in its calculation. 69 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
- 2014.pdf. 70 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/researchreport s/e 13k.pdf.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **77** of **763** units first generate power from a combustion turbine (the combustion cycle). The unused heat from the combustion turbine is then routed to a heat recovery steam generator (HRSG) that generates steam , which is then used to produce power using a steam turbine (the steam cycle). Combining these generation cycles in creases the overall efficiency of the system. Simple cycle combustion turbines use a single combustion turbine to produce electricity (i.e., there is no heat recovery or steam cycle ). The power output from these simple cycle combustion turbines can be easi ly ramped up and down making them ideal for “peaking” operations. Coal - fired utility boilers are primarily either pulverized coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is crushed (pulverized) into a powder in order to increas e 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 suspended in flowing air. Power can also be generated using gasification technology. An IGCC unit gasifies coal or petroleum coke to form a synthetic gas ( or syngas ) composed of carbon monoxide and hydrogen, which can be combusted in a combined cycle system to generate power . 3 . T echnological Developments and Costs***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **78** of **763** Natural gas prices have decreased dramatically and generally stabilized in recent years as new drilling techniques have brought additional supply to the marketplace and greatly increased the domestic resource base. As a result, natural gas prices are expected to be competitive for the foreseeable 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 discussed below, the cost of generation from a new natural
- gas fired power plant (a NGCC unit) is expected to be significantly lower than the cost of generation from a new coal
- fired power plant. 71 Other drivers that may influence decisions to build new power plants are increases in renewable energy supplies, often due to state and federal energy policies. As previously discussed, many states have adopted RPS, which require a certain portion of elect ricity to come from renewable energy sources such as solar or wind. The federal government has also offered incentives to encourage further deployment of other forms of electric generation including renewable energy sources and new nuclear power plants.

71 Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 201 5 http://www.eia.gov/forecasts/aeo/electricity_generation.html.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **79** of **763** 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 electric generating capacity through 2020, along with renewable energy, nuclear power, and a limited amount of coal with CCS. 72 While EIA data shows that natural gas is likely to be the most widely
- used fossil fuel for new construction of electric generating capacity through 2030 , a few coal - fired units still remain as viable projects at various advanced stages of construction and development. One new coal facility that has essentially completed construction, Southern Company's Kemper County Energy Facility, deploys IGCC with partial CCS . Additionally, another project, Summit Power's Texas Clean Energy Project (TCEP) , which will deploy IGCC with CCS , continue s as a viable project . 73 The EIA modeling projects that coal
- fired power generation will remain the single largest portion of the electricity sector beyond 2030. The EIA modeling also projects that few, if any, new coal
- fired EGUs will be built in this

72 http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf ; http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf ; http://prod
-http - 80
- 800498448.us
- east 1.elb.amazonaws.com/w/images/6/6d/0383%282011%29.pdf . 73 “Odessa coal - to - gas power plant to break ground this year”, Houston Chronicle (April 1, 2015).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **80** of **763** decade and that those that are built will have CCS. 74 Continued progress on these projects is consistent with the EIA modeling that suggests that a small number of coal - fired power plants may be constructed. The primary reasons for this rate of current and projected future development of new coal projects in clude highly competitive natural gas prices, lower electricity demand growth , and increases in the supply of renewable energy. We recognize, however, that a variety of factors may come into play 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 111. 75 4 . Energy Sector Modeling Various energy sector modeling efforts, including projections from the EIA and the EPA, forecast trends in new power plant construction and utilization of existing power

74 This project ion 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 gas prices and el ectricity demand, EIA does not project any additional coal
fired power plants beyond its reference case until 2023, in a case where power companies assume no GHGs emission limitations, and until 2024 in a case where power companies do assume GHGs emission limitations. 75 These sources received federal assistance under EPAct 2005. Se e section III.H.3.g below. However, none of the constraints in that Act affect the discussion in the text above, since that discussion does not relate to technology use or emissions reduction by these sources.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **81** of **763** plants that are consistent with the above
- described technological developments and costs. The EIA’s annual report, the AEO, forecasts the structure and developments in the power sector. These reports are based on economic modeling that reflects existing policy and regulations, such as state RPS programs and federal tax credits for renewables. 76 The current report, AEO 2015 , 77 (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 (referred to as “planned”); and (ii) projects in the reference case 78 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 Federal and State incentives. According to the AEO 2015, the vast majority of new generating capacity during this period will be either natural gas
- fired or renewable
sources . Similarly, the EIA projections from the last several years show that natural gas is likely to be the most widely
- used

76 http://www .eia.gov/forecasts/aeo/chapter_leg s_regs.cfm. 77 Energy Information Admin i stration’s Annual Energy Outlook for 2015 , Final Release available at http://www.eia.gov/forecasts/aeo/index.cfm . 78 EIA’s reference case projections are the result of its baseline assumptions for economic growth, fuel supply, technology, and other key inputs.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **82** of **763** fossil fuel for new construction of electric generating capacity through 2030 . 79 Specifically, the AEO 2015 projects 30.3 GW of additional 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 -projected nuclear, coal, and NGCC projects). The vast majority of this new electric capacity (20.4 GW) is already under development (under construction or in advanced planning); it includes about 0.7 GW of new coal - fired capacity, 5.5 GW of new nuclear capacity, 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 commenced construction and are thus not subject to these final standards ). The AEO 2015 also projects an addit ional 9.9 GW of new base load capacity additions, which are model
-projected (unplanned). This consists of 7.7 GW of new NGCC capacity, 1.2 GW of new geothermal capacity, 0.7 GW of new hydroelectric capacity, and 0.3 GW of new coal equipped with CCS (incent ivized with some government funding). Therefore, the AEO 2015 projection suggests that the new power generation capacity added through 2020 is expected to already meet the final emissions standards without

79 Annual Energy Outlook 2010, 2011, 2012, 2013 , 2014 and 2015 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **83** of **763** incurring further control costs. This is also true during the period from 2020 through 2030, where new model
-projected (unplanned) intermediate and base load capacity is expected to be compliant with the standards without incurring further control costs (i.e., an additional 31.3 GW of NGCC and no additional coal, for a total, from 2015 through 2030, of 39 GW of NGCC and 0.3 GW of coal with CCS). Under the EIA projections, existing coal
- fired generation wi ll 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 electricity in the electric power sector in both 2020 and 2025. The EPA modeling using the Integrated Planning Model (IPM), a detailed power sector model that the EPA uses to support power sector regulations, als o shows limited future construction of new coal - fired power plants under the base case. 80 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 plans, known
80 http://www.epa.gov/airmarkets/progsregs/epa
ipm/BaseCasev410.html#documentation .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **84** of **763** as integrated resource plans (IRPs). The EPA has reviewed publicly available IRPs from a range of companies (e.g., varying in size, location, current fuel mix), and these plans are generally consistent with both EIA and EPA modeling projections. 81 These IRPs indicate that companies
are focused on demand- side management programs to lower future electricity demand and are mostly reliant on a mix of new natural gas - fired generation and renewable energy to meet increased load demand and to replace retired generation capacity. Notwithstanding this clear trend towards natural gas
- fired generation and renewables, many of the IRPs highlight the value of fuel diversity and include options to diversify new generation capacity beyond natural gas and renewable energy. Several IRPs indicate that companies are considering new nuclear generation, including either traditional nuclear power plants or small modular reactors, and a smaller number are considering new coal - fired generation capacity with and without CCS technology. Based on public comments and on the information contained in these IRPs, the EPA acknowledges that a small number of new coal - fired power plants may be built in the near future. While

81 Technical Support Document
- “Review of Electric Utility Integrated Resource Plans” (May 2015), available in the rulemaking docket EPA
- HQ - OAR- 2013
- 0495.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **85** of **763** this outcome would be contrary to the economic modeling predictions, the agency understands that economic modeling may not fully reflect the range of factors that a particular company may consider when evaluating new generation options, such as fuel diversification. Further , it is possible that some of this potential new coal
- fired construction may occur because developers are able to design projects with specific business plans , such as the cogeneration of chemicals, which allow the source to provide competitively priced ele ctricity in specific geographic region s . D. Statutory Background The U.S. Supreme Court ruled in Massachusetts v. EPA that GHGs 82 meet the definition of “air pollutant” in the CAA, 83 and premised its decision in AEP v. Connecticut , 84 that the CAA displaced any federal common law right to compel reductions in CO 2 emissions from fossil fuel
- fired power plants , on its view that CAA section 111 applies to GHG emissions. CAA section 111 authorizes and directs the EPA to prescribe
new source performance standards (NSPS) applicable to certain

82 The EPA’s 2009 endangerment finding defines the air pollution wh ich may endanger public health and welfare as the well -mixed aggregate group of the following gases: CO 2 , methane (CH 4 ), nitrous oxide (N 2O), sulfur hexafluoride (SF 6 ), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs). 83 549 U.S. 497, 520 (2007). 84 131 S.Ct. 2527, 2537
- 38 ( 2011).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **86** of **763** new stationary sources (including newly constructed, modified and reconstructed sources). 85 As a preliminary step to regulation, the EPA must list categories of stationary sources that the Administrator, in his or her judgment, finds “cause[], or contribute[] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” The EPA has listed and regulated more than 60 stationary source categories under CAA section 111. 86 The EPA listed the two source categor ies at issue here in the 1970s
- listing fossil fuel
fired electric steam generating units in 1971 87 and listing combustion turbines in 197 7 . 88 Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new sources” in the category . 89 A “new source” is “any stationary source, the construction or modification of which is commenced after,” in general, final standards applicable to that source are promulgated or, if earlier, proposed. 90 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
85 CAA section 111(b)(1)(A). 86 See generally 40 CFR part 60, subparts D-MMMM. 87 36 FR 5931 (March 31, 1971). 88 42 FR 53657 (October 3, 1977). 89 CAA section 111(b)(1)(B). 90 CAA section 111(a)(2).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **87** of **763** pollutant not previously emitted.” 91 The EPA, through regulations, has determined that certain types of changes are exempt from consideration as a modification. 92 The NSPS general provisions (40 CFR part 60 , s ubpart A) provide that an existing source is considered to be a new source if it undertakes a “reconstruc tion,” which is the replacement of components of an existing facility to an extent that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards. 93 CAA section 111(a)(1) defines a “standard of performance” as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” This definition makes clear that the standard of performance must be based on “the best system of emission reduction ... adequately demonstrated” (BSER).

91 CAA section 111(a)(4). 92 40 CFR 60.2, 60.14(e). 93 40 CFR 60.15.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **88** of **763** The standard that the EPA develops, reflecting the performance of the BSER, is commonly a numeric emission limit, expressed as a numeric performance level that can either be normalized to a rate of output or input (e.g . , tons of pollution per amount of product produced

– a so - called rate -based standard), or expressed as a numeric limit on mass of pollutant that may be emitted (e.g. , 100 ug/m3

– parts per billion). Generally, the EPA does not prescribe a particular technol ogical system that must be used to comply with a standard of performance. 94 Rather, sources generally may select any measure or combination of measures that will achieve the emissions level of the standard. 95 In establishing standards of performance, the EPA has significant discretion to create subcategories based on source type, class , or size. 96 The text and legislative history of CAA section 111, as well as relevant court decisions , identify the factors that the EPA is to consider in making a BSER determination. The system of emission reduction must be technically feasible, the costs of the system must be reasonable, and the emission standard that the EPA promulgates based on the system of emission reduction must be achi evable. In addition, in identifying a BSER, the EPA
94 CAA sections 111 (b)(5) and (h). 95 CAA section 111(b)(5) . 96 CAA section 111(b)(2); see also Lignite Energy Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **89** of **763** must consider the amount of emissions reductions attributable to the system, and must also consider nonair quality health and environmental impacts and energy requirements . The case law addressing CAA sec tion 111 makes it clear that the EPA has discretion in weighing costs, amount of emission reductions, energy requirements, and impacts of non
- air quality pollutants , and may weigh them differently for different types of sources or air pollutants. We note that under the case law of the D.C. Circuit, another factor is relevant for the BSER determination: whether the standard would effectively promote further deployment or development of advanced technologies. Within the constraints just described, the EPA has discretion in identifying the BSER and the resulting emission standard. See generally S ection III.H below. For more than four decades, the EPA has used its authority under CAA section 111 to set cost
- effective emission standards which ensure that newly constructed, reconstructed , and modified stationary sources use the best performing technologies to limit emissions of harmful air pollutants. In this final action, the EPA is following the same well
- established interpretation and application of the law under CAA section 111 to address GHG emissions from newly constructed, reconstructed , and modified fossil fuel
- fired power plants. For each of the standards in this final action, the EPA considered a number of alternatives***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **90** of **763** and evaluated them against the statutory factors. The 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
- fired EGUs (which includes natural gas, petroleum and coal) that use steam
generating boilers in a category that it listed under CAA section 111(b)(1)(A), 97 and promulgated the first set of standards of performance for sources in that category, which it codified in subpart D. 98 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), 99 and the EPA promulgated standards of performan ce for that source category in 1979, which the EPA codified in subpart GG. 100 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 decades. In 1979 , the EPA divided subpart D into 3 subparts

– Da (“Standards

97 36 FR 5931 (March 31, 1971) 98 “Standards of Performance for Fossil
- Fuel - Fired Steam Generators for Which Construction Is Commenced After August 17, 1971,” 36 FR 24875 (December 23, 1971) codified at 40 CFR 60.40
- 46. 99 42 FR 53657 (October 3, 1977). 100 “Standards of Performance for Electric Utility St eam Generating Units for Which Construction is Commenced After September 18, 1978,” 44 FR 33580 (June 11, 1979).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **91** of **763** of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978”), Db (“Standards of Performance for Industrial
- Commercial
Institutional St eam Generating Units”) and Dc (“Standards of Performance for Small Industrial
- Commercial
- Institutional Steam Generating Units”)

– in order to codify separate requirements that it established for these subcategories. 101 In 2006, the EPA created subpart KKKK, ”Standards of Performance for Stationary Combustion Turbines,” which applied to certain sources previously regulated in subparts Da and GG . 102 None of these subsequent rulemakings, including the revised codifications, however, constituted a new listing under CAA section 111(b)(1)(A). The EPA promulgated amendments to subpart Da in 2006, which included new standards of performance for criteria pollutants for EGUs, but did not include specific standards of performance for CO 2 emissions. 103 Petitioners sought judicial review of the rule, contending, among other issues , that the rule was required

101 44 FR 33580 (June 11, 1979) 102 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 (March 20, 2009). 103 ”Standards of Performance for Electric Utility Steam Generating Units, Industrial
- Commercial
- Institutional Steam Generating Units, and Small Industrial
- Commercial
- Institutional Steam Generating Units, Final Rule. ” 71 FR 9866 (Feb ruary 27, 2006).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **92** of **763** to include standards of performance for GHG emissions from EGUs. 104 The January 8, 2014 preamble to the proposed CO 2 standards for new EGUs 105 includes a discussion of the GHG
related litigation of the 2006 Final Rule as well as other GHG
associated litigation. F. Development of Carbon Pollu tion Standards for Fossil Fuel
fired Electric Utility Generating Units On April 13, 2012, the EPA initially proposed standards under CAA section 111 for newly constructed fossil fuel
- fired electric utility steam generating units. 77 FR 22392 (“April 2012 proposal”). The EPA withdrew that proposal (79 FR 1352 (January 8, 2014) ), and, on the same day, proposed the standards addressed in this final rule. 79 FR 1430 (“January 2014 proposal”). Specifically, the EPA proposed standards 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 combustion turbines. In support of the January 2014 proposal, on February 26, 2014, the EPA published a notice of data availability (NODA) (79 FR 10750). Through the NODA and an associated technical support document, Effect of EPAct05 on Best System of Emission Reduction
104 State of New York, et al. v. EPA, No. 06

– 1322 **.** 105 79 FR 1430, 1444.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **93** of **763** for New Power Plants , the EPA solicited comment on its interpretation of the provisions in the Energy Policy Act of 2005 (EPAct05 ) , 106 including how the provisions may affect the 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 generating units. On June 18, 2014, the EPA proposed standards of performance 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 34959; June 2014 proposal). Specifically, the EPA proposed standards of performance for: (1) modified fossil fuel
- fired electric utility steam generating units, (2) modified natural gas
- fired stationary combustion turbines, (3) reconstructed fossil fuel
fired electric utility steam generating units, and (4) reconstructed natural gas - fired stationary combustion turbines. G. Stakeholder Engagement and Public Comments on the Proposals 1. Stakeholder Engagement
106 See section III.H.3 (g) below. The Energy Policy Act of 2005 (EPAct05) was signed into law by President George W. Bush on August 8, 2005. EPAct05 was intended to address energy production in the United States, including: (1) energy efficiency; (2) renewable energy; (3) oil and gas; (4) coal; (5) Tribal energy; (6) nuclear matters and security; (7) vehicles and motor fuels, including ethanol; (8) hydrogen; (9) electricity; (10) energy tax incentives; (11) hydropower and geothermal energy; and (12) climate change technology. www2.epa.gov/laws
- regulations/summary
- energy-policy
- act***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **94** of **763** The EPA has engaged extensively with a broad range of stakeholders and the general public regarding climate change, carbon pollution from power plants, and carbon pollution reduction opportunities. These stakeholders included industry and electric utility representatives, state and local officials, tribal officials, labor unions, non
- governmental organizations 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 li stening sessions to obtain information and input from key stakeholders and the public. Each of the five sessions had a particular target audience: the electric power industry, environmental and environmental justice organizations, states and tribes, coalit ion groups, and the petroleum refinery industry. The EPA conducted subsequent outreach prior to the June 2014 proposals of standards for modified and reconstructed 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 the GHG emission guidelines for existing EGUs, the outreach encompassed issues relevant to this rulemaking and provided an opportunity for the EPA to better understand previ ous state and stakeholder experience with reducing CO 2 emissions in the power sector. In***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **95** of **763** addition to 11 public listening sessions, the EPA held hundreds of meetings with individual stakeholder groups, and meetings that brought together a variety of stakeho lders to discuss a wide range of issues related to the electricity sector and regulation of GHGs under the CAA. The agency met with electric utility associations and electricity grid operators. Agency officials engaged with labor unions and with leaders
representing large and small industries . The agency also met with energy industries , such as coal and natural gas interests, as well as with represent atives of energy
- intensive industries, such as the iron and steel , and aluminum industries, to better understand the potential concerns of large industrial purchasers of electricity. In addition, the agency met with companies that offer new technology to prevent or reduce carbon pollution. The agency provided and encouraged multiple opportunities for engagement with state, local, tribal, and regional environmental and energy agencies. The EPA also met with representatives of environmental justice organizations, environmental groups, public health professionals, public health organizations, religious organizations , and other community stakeholders . The EPA received more than 2.5 million comments submitted in response to the original April 2012 proposal for newly constructed fossil fuel
- fired EGUs. Because the original proposal was withdrawn, the EPA instructed commenters that***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **96** of **763** wanted their c omments on the April 2012 proposal to be considered in connection with the January 2014 proposal to submit new comments to the EPA or to re
- submit their previous comments. We received more comments in response to the January 2014 proposal, as discussed in the section below. The EPA has given stakeholder input provided prior to the proposals, as well as during the public comment periods for each proposal, careful consideration during the development of this rulemaking and, as a result, it includes elements that are responsive to many stakeholder concerns and that enhance the rule. This preamble and the Response - to - Comments (RTC) 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 for newly constructed fossil fuel
- fired EGUs, the EPA provided a 60
- day public comment period. On March 6, 2014, in order to provide the public additional time to submit comments and supporting information, the EPA extended the comment period by 60 days, to May 9, 2014, giving stakeholders over 120 days to review, and comment upon, the January 2014 proposal, as well as the NODA. A public hearing was held on February 6, 2014, with 159 speakers presenting testimony.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **97** of **763** The EPA received more than 2 million comments on the proposed standards for newly constructed fossi l fuel - fired EGUs from a range of stakeholders that included industry and electric utility representatives, trade groups, equipment manufacturers, state and local government officials, academia, environmental organizations, and various interest groups. The agency received comments on a range of topics, including the determination that a new highly
- efficient steam generating EGU implementing partial CCS was the BSER for such sources , the level of the CO 2 standard based on implementation of partial CCS, the criteria that define which newly constructed natural gas
- fired stationary combustion turbines will be subject to standards, the establishment of subcategories based on combustion turbine size, and the rule’s potential effects on the Prevention of Significant Deterioration (PSD) preconstruction permit program and title 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 propo sal for modified and reconstructed fossil fuel
- fired EGUs, the EPA offered a 120
- day public comment period
- through October 16, 2014. The EPA held public hearings in four locations during the week of July 28, 2014. These hearings also addressed EPA’s June 18, 2014 proposed emission guidelines for existing fossil fuel
- fired EGUs***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **98** of **763** (reflecting the connections between the proposed standards for modified and reconstructed sources and the proposed emission guidelines). A total of 1,322 speakers testified, and a further 1,450 attended but did not speak. The speakers were provided the opportunity to present data, views , or arguments concerning one or both proposed actions **.** The EPA received over 200 comments on the proposed standards for modified and reconstruc ted fossil fuel
- fired EGUs from a range of stakeholders similar to those that submitted comments on the January 2014 proposal for newly constructed fossil fuel
- fired EGUs (i.e., industry and electric utility representatives, trade groups, equipment manufac turers, state and local government officials, academia, environmental organizations, and various interest groups). The agency received comments on a range of topics, including the methodology for determining unit
- specific CO 2 standards for modified steam generating units and the use of supercritical boiler conditions as the basis for the CO 2 standards for certain reconstructed steam generating units. Many of the comments regarding modified and reconstructed natural gas - fired stationary combustion turbines are similar to the comments regarding newly constructed combustion turbines described above (e.g., applicability criteria and subcategories based on turbine size).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **99** of **763 III. Regulatory Authority**  **, Affected EGUs**  **and Their Standards, and Legal Requirements**  In this section, we describe our authority to regulate CO 2 from fossil fuel
- fired EGUs. We al so describe our decision to combine the two existing categories of affected EGUs

– steam generators and combustion turbines
- into a single category of fossil fuel
- fired EGUs for purposes of promulgating standards of performance for CO 2 emissions . We also explain that we are codifying all of the requirements in this rule for new , modified , and reconstructed affected EGUs in new subpart TTTT of part 60 of Title 40 of the Code of Federal Regulations . In addition, we explain which sources are and are not affec ted by this rule, and the format of these standards. Finally, we describe the legal requirements for establishing these emission standards. A. Authority to Regulate Carbon Dioxide from Fossil Fuel
-fired EGUs The EPA’s authority for this rule is CAA section 111(b)(1). CAA section 111 (b)(1) (A ) requires the Administrator to establish a list of source categories to be regulated under section 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 reasonably be anticipated to endanger public health and welfare .” This***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **100** of **763** determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly” component and the “endanger public health and welfare” component of the determination. Then, for the source categories listed under section 111(b)(1)(A), the Administrator promulgates, under section 111(b)(1) (B), “standards of performance for new sources within such category.” In this rule, the EPA is establishing standards under section 111(b)(1)(B) for source categories that it has previously listed and regulated for other pollutants and which now are being regulated for an additional pollutant. Because of this, there are two aspects of section 111(b)(1) that 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 establish standards of performance for the CO 2 emissions from those
sources . Under the plain language of CAA section 111 (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 contribution , the statute is clear that the endangerment finding is made with***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **101** of **763** 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 provisions that do require the EPA to make endange rment findings for each particular pollutant that the EPA regulates under those provisions. E.g., CAA sections 202(a)(1), 211(c)(1), 231(a)(2)(A). See American Electric Power v. Connecticut , 131 S. Ct. 2527, 2539 (2011) (“the Clean Air Act directs 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 endanger public health or welfare.’ § 7411(b)(1)(A) .”) (emphasis added). Second, once a source category is listed, the CAA does not specify what pollutants should be the subject of standards from that source category. The statute, in section 111(b)(1)(B), simply directs the EPA to propose and then promulgate regulations “establishing Federal standards of performance for new sources within such category.” In the absence of specific direction or enumerated criteria in the statute concerning what pollutants from a given source category should be the subject of standards , it is appropriate for EPA to exercise its authority***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **102** of **763** to adopt a reasonable interpretation of this provision. Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 843
- 44 (1984). 107 The EPA has previously interpreted this provision as granting it the discretion to determine which pollutants should be regulated. See Standards of Performance for Petroleum Refineries, 73 Fed. Reg. 35838 (June 24, 2008) (concluding that the statute provides “the Administrator with significant flexibility in determining which pollutants are appropriate for regulation under section 111(b)(1)(B)” and citing cases). Further, in directing the Administrator to propose and promulgate regulation s 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 similar statutory phrasing from CAA section 231(a) (3) and concluded that “[t]his delegation of authority is both explicit and extraordinarily 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 approp riate for regulation under section
107 In Chevron, the U.S. Supreme Court held that an agency must, at Step 1, determine whether Congress’s intent as to the specific matter at issue is clear, and, if so, the agency must give effec t to that intent. If Congressional intent is not clear, then, at Step 2, the agency has discretion to fashion an interpretation that is a reasonable construction of the statute.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **103** of **763** 111(b)(1)(B), the EPA has in the past provided a rational basis for its decisions. See National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) ( The “ court discussed, but did not review, the EPA’s reasons for not promulgating standards for NOX , SO 2 and CO from lime plants . ”); Standards of Performance for Petroleum Refineries, 73 Fed. Reg. at 35859
- 60 (June 24, 2008) (providing reasons why the EPA was not promulgating GHG standards for petroleum refineries as part of that rule). Though these previous examples involved the EPA providing a rational basis for not setting standards for a given pollutant, a similar approach is appropriate where the EPA determines that it should set a standard for an additional pollutant for a source category that was previously listed and regulated for other pollutants. In this rulemaking, the EPA has a rational basis for 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, in 2009, the EPA made a finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare, and in 2010, the EPA denied petitions to reconsider that finding. The EPA extensively reviewed the available science concerning GHG pollution and its impacts in taking those actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit upheld the finding***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **104** of **763** and the denial of petitions to reconsider. 108 In addition, assessments from the NRC , the IPCC, and other organizations published after 2010 lend further credence to the validity of the Endangerment Finding. No information that commenters have presented or that the EPA has reviewed provides a basis for reaching a different conclusion . Indeed, current and evolving science discussed in detail in S ection II.A of this preamble is confirming and enhancing our unders tanding of the near
- 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 to occur as a result . Moreover, the high level of GHG emissions from fossil fuel fired EGUs makes clear that it is rational for the EPA to regulate GHG emissions from this sector. EGUs emit almost one
third of all U.S. GHGs and comprise by far the largest stationary source category of GHG emissions ; indeed, a s 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 millions of tons each year . See, e.g . , S ection V.K below ( noting that even the
108 Coalition for Responsible Regulation v. EPA, 684 F. 3d at 102, 119
- 126 (D.C. Circuit 2012).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **105** of **763** difference in CO 2 emissions between a highly efficient SCPC and the same unit meeting today’s standard of performance 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 required to make a new endangerment finding before it may regulate CO 2 from EGUs. We disagree, for the reasons discussed above. Moreover, a s discussed in the January 2014 proposal, 109 even if CAA section 111 require d the EPA to make endangerment and cause - or contribute significantly findings as prerequisites for this rulemaking, then , so far as the “ CO 2 endanger s public health and welfare” component of an endangerment finding is concerned, the the information and conclusions described above should be considered to constitute the requisite endangerment finding. Similarly, so far as a cause
- or - contribute significantly finding is concerned, the information and conclusions described above should 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 EPA’s 2009 Endangerment Finding and 2010 denial of petitions to reconsider that Finding, coupled with the subsequent assessments from the IPCC and NRC that describe scientific developments

109 79 FR 1430, 1455
- 56 (January 8, 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **106** of **763** since those EPA actions. In addition, we have reviewed comments presenting other scientific information to determine whether that information has any meaningful impact on our analysis and conclusions . More specifically, our approach here

– reflected in the information and conclusions described above

– is substantially 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, among other things (id. at 119
- 120), the “substantial ... body of scientific evidence marshaled by EPA in support of the Endangerment Finding”; the “substantial record evidence that anthropogenic emissions of greenhouse gases ‘very likely’ caused wa rming of the climate over the last several decades”; “substantial scientific evidence ... that anthropogenically induced climate change threatens both public health and public welfare” through “extreme weather events, changes in air quality, increases in food- and water -borne pathogens, and increases in temperatures”; and “substantial evidence ... that the warming resulting from the greenhouse gas emissions could be expected to create risks to water resources and in general to coastal areas”). The facts, unfortunately, have only grown stronger and the potential adverse consequences of CO 2 emissions to public health and the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **107** of **763** environment more dire in the interim. Accordingly, that approach would support an endangerment finding for this rulemaking. 110 Likewise, if the EPA were required to make a cause
- or contribute
- significantly finding for CO 2 emissions from the fossil fuel
- fired EGUs as a prerequisite to regulating such emissions under CAA section 111, the same facts that support our
110 Nor does the EPA consider the cost of potential standards of performance in making this Finding. Like the Endangerment Finding under section 202(a) at issue in Massachusetts , the pertinent issue is a scientific inquiry as to whether an endangerment to public health or welfare from the relevant air pollution may reasonably 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 to make a positive endangerment finding to serve other policy grounds. 549 U.S. at 532
- 35. In this regard, an endangerment finding is analogous to setting nationa l ambient air quality standards under section 109(b), which similarly call on the Administrator to set standards that in her “judgment” are “requisite to protect the public health . ” The EPA is not permitted to consider potential costs of implementation in s etting these standards. Whitman v. American Trucking Assn’s , 521 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) c ontains no terms such as “necessary and appropriate” that 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 Michigan , slip op. pp. 7
- 8. The EPA, of cours e, must consider costs in determining whether a best system of emission reduction is adequately demonstrated and so can form the basis for a section 111(b) standard of performance, and the EPA has carefully considered costs here and found them to be reasonable. See Section V. H and V. I below. The EPA also has found that the rule’s quantifiable benefits exceed regulatory costs under a range of assumptions if new capacity were to be built. RIA chapter 5 and Section XIII.G below. Accordi ngly, this endangerment finding would be justified if ( contrary to our view) it is both required and costs are to be considered as part of the finding.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **108** of **763** rational basis determinat ion would support such a finding. As shown in Tables 3 and 4 in this preamble , fossil fuel
- 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 emissions, and are responsible for almost three times as much as the emissions from the next ten stationary source categories combined . The CO 2 emissions from even a single new coal
- fired power plant may amount to millions of tons each year , and the CO 2 emissions from even a single NGCC unit may amount to one million or more tons per year . It is not necessary in this rulemaking for the EPA to decide whether it must identify a specific threshold for the amount of emissions from a source category that cons titutes a significant contribution ; under any reasonable threshold or definition, the emissions from combustion turbines and steam generators are a significant contribution . Indeed, these emissions far exceed in magnitude the emissions from motor vehicles, which have already been held to contribute to the endangerment. See Coalition for Responsible Regulation , 684 F. 3d at 121 (“substantial evidence” supports EPA’s determination “that motor -vehicle emissions of greenhouse gases contribute to climate change and thus to the endangerment of public health and welfare”). 111

111 The “air pollution” defined in the Endangerment Finding is***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **109** of **763** 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 steam generating boilers as a new category subject to CAA section 111 rulemaking, and in 1979 the EPA listed fossil fuel
- fired combustion turbines as a new category subject to the CAA section 111 rulema king. In the ensuing years, the EPA has promulgated standards of performance for the two categories and codified those standards, at various times, in 40 CFR part 60 , subparts D, Da, GG, and KKKK. In the January 2014 proposal of carbon pollution standards for newly constructed EGUs (79 FR 1430) and the June 2014 the atmospheric mix of six long
- lived and directly emitted greenhouse gases: carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxi de (N 2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfu r hexafluoride (SF 6 ). See 74 FR at 66497. The standards of performance adopted in the present rulemaking address only one component of this air pollution: CO 2 . This is reasonable, given that CO 2 is the air pollutant emitted in largest volume by the source category, and which is (necessarily) emitted by every affected EGU. There is, of course, no requirement that standards of performance address each component of the air pollution which endangers. Section 111(b)(1)(A) requires the EPA to establish “standards of performance” for listed source categories, and the definition of “standard of performance” in section 111 (a)(1) does not specify which air pollut ants must be controlled . See also section III.G above explaining that CH 4 and N 2O 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
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– Do Not Cite, Quote or Release During Review *** Page **110** of **763** proposal of carbon pollution standards for modified and reconstructed EGUs (79 FR 34960), the EPA proposed separate standards of performance for new, modified, and reconstructed sources in the two c ategories. The EPA took comment on combining the two categories into a single category solely for purposes of the CO 2 emissions from new, modified, and reconstructed affected EGUs. In addition, the EPA proposed codifying the standards of performance in the same Da and KKKK subparts that currently contain the standards of performance for other pollutants 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 generator and combustion turbine categories into a single category of fossil fuel - fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combini ng the two categories is reasonable because they both provide the same product : electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart of the regulations; as a***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **111** of **763** result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants . Because the se two source categories are pre
- existing listed source categories and the EPA will not be subjecting any additional sources in the categories to CAA regulation for the first time , the combination of these two categories is not considered a new source category subject to the listing requirements of CAA section 111(b)(1)(A). As a result, this final rule does not list a new category under CAA section 111(a)(1)(A), nor does this final rule revise either of the two source categories. Thus , the EPA is not required to make a new endangerment and contribution finding for the combination of the two categories , 112 although as discussed in the previous section, the evidence strongly supports such findings. Thus, the EPA has found, in the alternative, that this category of sources contributes significantly to air pollution which may be reasonably anticipated to endanger public health and welfare. C. Affected Units
112 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 (PM2.5) was already included as a sub
- set of the listed pollutant particulate matter, it was not a new pollutant necessitating a new listing).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **112** of **763** We generally refer to fossil fuel
- fired electric generating units that would be subject to a CAA section 111 emission 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 combined cycle configuration) that meets the applicability criteria. Affected EGUs include those that commenced construction after January 8, 2014 and meet the specified applicability criteria and, for modifications and reconstructions, EGUs that commenced 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 input of fossil fuel 113 and (2) serve a generator capable of supplying more than 25 MW net to a utility distribution system (i.e., for sale to the grid). 114 However, we are not finalizing CO 2 standards for 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 limits the use of fossil fuels to 10 percent or less of the ir heat input capacity

113 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. 114 We refer to the capability to supply 25 MW net to the grid as the "total electric sales criterion."***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **113** of **763** on an annual basis; (2) combined heat and power (CHP) units that
are subject to a federally enforceable permit limiting annual net - electric sales to no more than the unit ’s design efficiency multiplied by its potential electric output , or 219,000 MWh or less , whichever is greater ; (3) stationary combustion turbines that are not physically capable of combusting natural gas (e.g., not conne cted to a natural gas pipeline ) ; ( 4 ) utility boilers and IGCC units that have always been subject to a federally enforceable permit limiting annual net - electric sales to one third or less of their potential electric output (e.g., limiting hours of operation to les s than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less; ( 5 ) municipal waste combustors that are subject to subpart Eb of this part; and ( 6 ) commercial or industrial solid waste 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 not 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 under development . This section discusses the se sources and our rationale for not issuing standards for them. Because the rationale applies to both steam generating units and combustion turbines , we are describing it here rather than in the separate***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **114** of **763** steam generating unit and combustion turbine discussions. We discuss the proposed applicability criteria , the topics where the agency solicited comment, a brief summary of the relevant comments, and the rationale for the final applicabilit y approach for these sources . 1. Dedicated Non
- fossil Fuel Units The proposed applicability for newly constructed EGUs included those that primarily combust fossil fuels (e.g., coal, oil , and natural gas). The proposed applicability criteria 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 . 115 Under the proposed approach, applicability under the final NSPS for CO 2 emissions could have change d on an annual basis depending on the composition of fuel burned. We solicited comment on several aspects of the proposed applicability criteria for non - fossil fuel units. Specifically, we solicited comment on a broad applicability approach that would include
non - fossil fuel - fired units as affected units , but that would impose an alternate standard when the unit fires fossil fuels for 10 percent or less of the heat input during the 3
- year applicab ility
- determination period. We solicited comment on whether, if such a subcategory is warranted, the applicability
- 115 We refer to the fraction of heat input derived from fossil fuels as the "fossil fuel
- use criterion."***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **115** of **763** determination 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 alternate numerical limit or "no emission standard." While the proposed exemption applied to all non
- fossil 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 none of the analyses supporting the standards include d biomass
- fired units. These c ommenters also stated that the proposed standards have not been adequately demonstrated as achievable by these units and that the rule offered no basis for regulating sources that combust insignificant amounts of fossil fuels. They suggested that if dedicated biomass units must be included under these CAA section 111 standards for fossil fuel - fired units, they should be included in a separate subcategory after a subsequent proposal and comment period based on relevant data . Many commenters supported an exclusion for biomass
- fired units that fire no more than 10 percent fossil fuels. Some commenters suggested that the 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **116** of **763** the EPA using IPM show that biomass generation is expected to quadruple over the next 10 years. These commenters said that dedicated biomass units should be regulated consistently with coal units. One commenter supported ensuring that the CO 2 standards issued pursuant to CAA section 111(d) continue to apply to existing EGUs when those EGUs modify or reconstruct in ways that cause the units to derive 10 percent or less of their heat input from fossil fuel s because allowing modified and reconstructed EGUs to escape 111(d) standards would undermine the coherence of the proposed 111(d) regulatory system. Many commenters supported the proposed 3
- year averaging period for the fossil fuel
- use criterion because it provides greater flexibility for operators to use fossil fuels when supply chains for biogenic fuels are disrupted, during unexpected malfunctions of biomass handling systems, or when the unit’s maximum generating capacity is requi red by system operators for reliability reasons. Many commenters supported the 3
- year averaging period because it is consistent with the final requirements under the EPA’s Mercury and Air Toxics Standards ( MATS ) and would allow biomass
- fired units to use some fossil fuels for flame stabilization without triggering applicability. Some commenters recommended including an additional 15 percent fossil fuel
- use threshold that would be calculated on an annual basis. Some commenters requested that the EPA clarify the method***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **117** of **763** an operator should use during the first 3 years of operations to determine if a particular unit will meet the 10 percent fossil fuel - use threshold . Others asked whether or not an affected facility has a compliance obligation during the first 3
- year period and , if an affected facility does not meet the 10 percent fossil fuel
- use threshold during several 12
-month periods during the first 3 years, whether compliance calculations would be required for such 12
-month periods . Other commenters had concerns with the 3
- year averaging period, stating that a source would no longer be subject to the NSPS if it fell below the threshold for any of the applicability metrics that the EPA proposed to calculate on a 3
- year (or, in some cases, annual) basis . They argued that this would creat e a situation in which no one would know whether a particular plant will be subject to the standards until years after the emissions had already occurred. Some commenters were concerned that plants operating near the threshold could move in and out of the regulatory system, which would provide complications for compliance, enforcement, and permitting. After considering these comments, the EPA has concluded that the proposed fossil fuel
- use criterion based on the actual amount of fossil fuel burned is not an ideal approach to determine applicability . As commenters pointed out, facilities , permitting authorities , and the public would not know when***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **118** of **763** construction is commenced whether a facility will be subject to the final NSPS , and after operation has commenced , a unit could move in and out of applicability each year. The intent of this rulemaking is to establi sh 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 fossil fuel
use 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 standards so long
as they are subject to a federally enforceable permit that limits the ir use of fossil fuels to 10 percent or less of the ir heat input capacity on an annual basis . This approach establishes clear applicability criteria and avoids the prospect of units moving in and out of applicability based on their actual fuel use in a given year . Consistent with the applicability approach in the steam generating unit criteria pollutant NSPS, subpart Da, the final fossil fuel
- use criteri on does not include “ constructed for the purpose of ” language . Therefore, an owner or operator could change a unit ’ s applicability in the future by seeking a modification of the unit’s permit conditions . A unit with the appropriate permit limitation will not be subject to the requirements in this rulemaking . Similarly, an existing unit that takes a permit***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **119** of **763** limitation restricting fossil
- fuel use would no longer 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 average for calculating compliance with the final fossil fuel
- use criterion . Ultimately, we concluded that an annual average would provide sufficient flexibility for dedicated non
- fossil units to combust fossil fuels for flame stabilization and other ancil lary 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 higher CO 2 emissions, so long as they curtailed fossil
- fuel use in a later year. This would defeat the purpose of the criterion, which is to exempt dedicated non
- fossil units only. Finally, we are finalizing the 10 percent fossil
- fuel use threshold in relation to a unit’s heat input capacity rather than its actual 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 use of CHP units . A CHP unit can use a boiler, combustion turbine, reciprocating engine, or various other generating technologies***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **120** of **763** to generate electricity and useful thermal energy in a single, integrated system. CHP units are generally more efficient than conventional power plants because the heat that is normally wasted in a conventional power generation cooling system (e.g., cooling towers) is recovered as useful thermal output instead . While the EPA did propose some applicability provisions specific to CHP units (e.g., subtract purchased power of adjacent facilities when determining total electric sales), in general , the proposed applicability criteria for electric
- only units and CHP units were similar. The intent of the proposed total and percentage electric sales criteria was to cover only utility CHP units , not industrial CHP units . To the extent that the proposal’s applicability provisions would have the effect of covering i ndustrial CHP units , we solicited comment on an appropriate applicability exemption, and the criteria for that exemption, for highly efficient CHP facilities. We also solicited comment on eliminating the 219,000 MWh aspect of the total electric sale s criterion for stationary combustion turbine s operating as CHP facilities . Many commenters supported the exclusion of CHP units as a means of encouraging capital investments in highly efficient and reliable distributed generation technologies. These c ommenters recommended that the EPA adopt an explicit exemption for CHP units at facilities that are classified as industrial (e.g.,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **121** of **763** gas - fired CHPs within SIC codes 2911

– petroleum refining , 13

– oil and gas extraction , and other industrial SIC codes 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 industri al - commercial
- institutional CHP units that supply, on a net basis, more than two
- thirds of their potential combined thermal and electric energy output and more than 450,000 MWh net
- electric output to a utility power distribution system on an annual basis for five consecutive calendar years . The commenter also suggested that CHP units which have total thermal energy production that approaches or exceeds their total electricity production should be exempted. Other c ommenters suggested exempting CHP units by fuel type
or based on the definition of potential electric output. For example, some c ommenters suggested modifying the percent age electric sales threshold to be based on net system efficiency ( including useful thermal output) rather than just the rated net - electric
- output efficiency . They also suggested that the
applicability criteria should use a default efficiency of 50 percent for CHP units. Some commenters suggested that a CHP unit should not be considered an affected EGU if 20 percent or more of its total gross or net energy output consisted of useful thermal output on a 3
- year rolling average basis. Other***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **122** of **763** commenters said that highly efficient CHP units that achieve an overall efficiency level of 60 to 70 percent or higher should be excluded from applicability . Several commenters opposed the removal of the 219,000 MWh aspect of the total electric sales criterion because it provides additional assurance that smaller industrial CHP units will not be subject to the standards . The intent of this rulemaking is to cover only utility CHP units because they serve essentially the same purpose as electric
- only EGUs (i.e., the sale of electricity to the grid ). Industrial CHP units , on the other hand, serve a different primary purpose (i.e., providing useful thermal output with electric sales as a by-product). With these facts in mind and after considering the comments, the EPA has concluded that it is appropriate to consider two factors for the final CHP 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 concluded that SIC code classification is not a sufficient indicator of the purpose (i.e., it does not correlate to useful thermal output) or environmental benefit s (i.e., efficiency) of a unit. Further,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **123** of **763** an exemption based on SIC code could result in circumvention of the intended applicability. For example, this approach would allow a new EGU to locate near an industrial site , provide a trivial amount of useful thermal output to that site , sell electricity to the grid, and nonetheless avoid applicability . Similarly, increasing the electric sales criteria to 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 thermal output being greater than 20 percent of total output, thermal output being greater than electri c output, or overall design efficiency value would identify whether the primary purpose of a unit is to generate thermal output, but they would not recognize the environmental benefit s of highly efficient CHP units . While overall efficiency may appear to be a good indicator of environmental benefit s , this is not always the case with CHP units . Overall efficiency is a function of both efficient design and the power to heat ratio (the amount of electricity relative to the amount of useful thermal output). For example, boiler
based CHP units tend to produce large amounts of useful thermal output relative to electric output and tend to have high overall efficiencies . For units producing primarily useful thermal output , the equivalent separate heat and power efficiency (i.e.,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **124** of **763** the theoretical overall efficiency if the electricity and useful thermal output were produced by a stand- alone EGU and standalone boiler) would approach that of a stand- alone boiler (e.g., 80 percent). However, c ombustion turbine
-based CHP units tend to produce relatively equal amounts of electricity and useful thermal output. In this case, the equivalent separate heat and power efficiency would be closer to 65 percent. Therefore, an exempti on based on overall efficiency is not an indication of the fuel savings a CHP unit will achieve relative to separate heat and power. Further, this approach would encourage the development of CHP units that just meet the efficiency exemption criterion and would still cover many combustion turbine
-based industrial CHP units . Conversely , while an exemption based on fuel savings relative to separate heat and power would recognize the environmental benefit of highly efficient CHP units , it would not consider the primary purpose of the CHP unit. In the end, the EPA has conclude d that maintaining the proposed percentage electric sales criterion with two adjustments will addresses both factors with which we are concerned . First , we are changing the definition of “potential electric output ” to be based on overall net efficiency at the maximum electric production rate , instead of just electric
- only efficiency. Second, we are changing the percentage electric sales criterion to reflect the sliding scale, which is the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **125** of **763** overall design efficiency , calculated at the maximum useful thermal rating of the CHP unit (e.g., a CHP unit with a extraction condensing steam turbine would determine the efficiency at the 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 industrial CHP unit s by providing a more generous percentage electric sales exemption to CHP units with high thermal output. As described previously, CHP units with high thermal loads tend to be more efficient and will therefore have a higher allowable percentage electric sales. By amending both the definition of “potential 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 all of their electric output to the grid. As the relative amount of electricity generated by the CHP unit increases, efficiency will generally decrease, thus limiting allowable electric sales before applicability is triggered . This approach also recognizes the environmental benefit s of increased efficiency by encouraging industrial CHP uni ts to be designed as efficiently as possible to take advantage of the higher electric sales permitted by the sliding scale .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **126** of **763** In conclusion, a CHP unit will be an affected source unless it is subject to a federally enforceable permit limiting annual total electric sales to less than equal to the unit’s design efficiency multiplied by its potential electric output or 219,000 MWh , whichever is greater. This final applicability criterion will only cover CHP units that condense a large portion of steam generated by the unit for the purpose of supplying electric power to the grid . CHP facilities that do not have a condensing steam turbine (e.g., simple cycle combustion turbines with a HRSG and boiler
-based systems with a backpressure steam turbine) would generally not be physically capable of selling enough electricity to meet the applicability
c riterion, even if they sold 100 percent of the electricity generated and did not subtract out the electric ity 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. CHP facilities with a steam extraction condensing steam turbine will determine their potential electric output based on their efficiency on a net basis at the maximum electric production rate at the base load heat input rat ing (e.g., the CHP is condensing as much steam as possible to create electricity instead of using it for useful thermal output) . We have concluded that it is necessary for CHP units with extraction condensing steam turbines to calculate***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **127** of **7 63**  their potential el ectric output at the maximum condensing level to avoid circumvention of the applicability criteria. For example, a CHP unit could locate next to an industrial host and have the capability of selling significant quantities of useful thermal output without ever actually intending to supply much, if any, of the useful thermal output as an approach to avoid applicability. If we calculated the potential electric output at the maximum level of thermal output this type of CHP unit could operate at full condensing mode at base load conditions for the entire year and still not exceed the electric sales threshold. The owner/operator will be able to determine during the permitting process if the unit is subject to the final standards in this rule . New EGUs with only limited useful thermal output will be subject to the final standards, but the vast majority of new CHP units will be classified as industrial CHP and will not be subject to the final standards. The EPA has concluded that this approach is similar to exempting CHP facilities that s ell less than half of their total output (electricity plus thermal), but has the benefit of accounting for overall design efficiency. This approach both limits applicability to the industrial CHP units and encourages the installation of the mos t efficient CHP systems because more efficient designs will be able to have higher permitted electric sales while not being subject to the CO 2 standards included in this rulemaking.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **128** of **763** 3. Municipal Waste Combustors and Commercial and I ndustrial S olid Waste I ncinerators The purpose of th is rulemaking is to establish CO 2 standards for fossil fuel
- fired EGUs. Municipal waste combustors and commercial and industrial solid waste incinerators typically have not been included in this source category. Therefore, even if one of these types of units meets the general heat input and electric sales criteria , we are not finalizing CO 2 emission standards for municipal waste combustor s subject to subpart Eb of this part and commercial and industrial solid waste incinerat or s subject to subpart CCCC of this part. 4. Certain Projects Under Development The EPA proposed that a limited class of projects under development should not be subject to the proposed standards. These were planned sources that may be capable of commencing 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 p roposed standard of performance. See 79 FR 1461 and CAA section 111 (a)(2). The EPA proposed that these sources would not be subject to the generally
- applicable standard of performance, but rather would be subject to a unit
- specific permitting determination if and when construction actually
commences. The EPA indicated that there could be three sources***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **129** of **763** to which this approach could apply, and further indicated that the EPA could ultimately adopt the generally
- applicable standard of performance for these sour ces (if actually constructed). 79 FR 1461. As explained at section III.J below, the EPA is finalizing this approach in today’s action. 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 standard. E. Coal Refuse In the April 2012 proposal, we solicited comment on subcategorizing and exempting EGUs that burn over 75 percent coal refuse on an annual basis. Multiple commenters supported the exemption, citing numerous environmental benefits of remediating coal refuse piles. Observing that coal refuse
- fired EGUs typically use fluidized bed technologies, othe r commenters disagreed with any exemption, specifically citing the N 2O emissions from fluidized bed boilers. In light of the environmental benefits of remediating coal refuse piles cited by commenters, the limited amount of coal refuse, and the fact that
a new coal refuse - fired EGU would be located in close proximity to the coal refuse pile, we sought additional comments regarding a subcategory for coal refuse - fired EGUs in the January 2014***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **130** of **763** proposal . Specifically, we requested additional information on the net environmental benefits of coal refuse
- fired EGUs and information to support an appropriate emissions standard for coal refuse - fired EGUs. One commenter on the April 2012 proposal stated that existing coal refuse piles are naturally combusting at a rate of 0.3 percent annually, and we requested comment on this rate and the proper approach to account for naturally occurring emissions from coal refuse piles in the January 2014 proposal . Commenters said that a performance standard is not feasible for coal refuse CFBs since there is no economically feasible way to capture CO 2 through a conveyance designed and constructed to capture CO 2 . Commenters suggested that the EPA establish BSER for GHGs at modified coal refuse CFBs as a bo iler tune
- up that must be performed at least every 24 months. Commenters stated that the EPA should exempt coal refuse CFB units relative 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 store coal waste. In contrast, one commenter saw no legitimate basis for coal refuse to be subcategorized and stated that they should be treated in the same manner as all other coal
- fired EGUs .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **131** of **763** 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 facilities to install CCS are similar to coal
- fired EGUs burning any of the primary coals, and the final applicable requirements and standards in the rule do not preclude the development 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 designed as CHP units. Due to the expense of transporting coal refuse long distances, we anticipate that any new coal refuse - fired 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 requirements of this rule would not apply. F. Format of the Output -based Standard 1. Net and Gross Output -based S tandards For all newly constructed units, the EPA proposed standards as gross output emission rates consistent with current 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 solicited

116 79 FR 1447
- 48.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **132** of **763** comment on finalizing equivalent net
- output -based standards either as a compliance alternative or in lieu of the proposed gro ss - output -based standards. Net output is the gross electrical output less the unit’s total parasitic (i.e., auxiliary) power requirements. A parasitic load for an EGU is a load or device powered by electricity, steam, hot water, or directly by the gross output of the EGU that does not contribute electrical, mechanical, or useful thermal output. In general, parasitic energy demands include less than 7.5 percent of non
- I GCC and
non - CCS coal - fired station power output, approximately 15 percent of non - CCS IGCC -based coal - fired station power 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 considered when determining the emission rate. Net output is used to recognize the environmental benefits of (1) EGU designs and control equipment that use less auxiliary power, (2) fuels that require less emissions control equipment and (3) higher efficiency motors, pumps, and fans. For modified and reconstructed combustion turbines, the EPA also proposed standards as gross output emission rates, but solicited comment on finalizing net
output standards. The rationale was that due to the low auxiliary loads in non
- CCS NGCC designs, the difference between a gross - output standard and a net - output standard has a limited***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **133** of **763** impact on environmental performance. Auxiliary loads are more significant for modified and reconstructed boilers and IGCC units, and the EPA proposed standards on a net output 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. However, 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) consistently across all CAA section 111(b) standards for new, modified, and reconstructed EGUs. Many commenters support ed gross - output -based standards , maintaining that a net - output standard penalizes the operation of air pollution control equipment. Several commenters disagreed with the agency's proposed rationale that a net
- output standard would provide incentive to minimize auxiliary loads. The commenters believe utility commissions and existing economic forces already provide utilities with appropriate incentives to properly manage all of these factors. Some commenters supported a gross - output -based standard because variations in site conditions (e.g., available natural ga s pressure, available cooling water sources, and elevation) will likely penalize some owners and benefit others simply through variations in their***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **134** of **763** particular plant
- site conditions if a net basis is used. Several commenters stated that if the final rule in cludes a net - output based standard, it should be included as an option in conjunction with a gross
- output -based option. Several commenters opposed net - output -based standards because they believe it is difficult to accurately determine the net output of an EGU. They pointed out that many facilities have transformers that support multiple units at the facility, making unit
- level reporting difficult. These commenters also stated that station electric services may come from outside sources to supply certain anc illary loads. One commenter stated that the benefit of switching to net
- output -based standards would be small and would not justify the substantial complexities in both defining and implementing such a standard. Conversely, other commenters stated that net -metering is a well
- established technology that should be required, particularly for newly constructed units. Other commenters , however, maintained that the final 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 to consumers . These commenters believe that, at a minimum, net
- output -based standards should be included as an option in the final rule.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **135** of **763** We are only final izing gross
- output -based standards for utility boilers and IGCC units. Providing an alternate net
output -based standard that is based on gross
- output -based emissions data and an assumed auxiliary load is most appropriate when the auxiliary load can be reas onably estimated and the choice between the net
- and gross - output -based standard will not impact the identified BSER. For example, the auxiliary 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 choices. However, in the case of utility boilers, we have concluded that we do not have sufficient information to establish an appropriate net
- output -based standard that would not 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 combustion turbines, owners/operators of utility boilers have multiple technology pathways available to comply with the actual emission standard. The choice of both control technologies and fuel impact the overall auxiliary load. For example, a coal
- fired hybrid EGU (e.g., one that includes integrated solar thermal equipment for feedwater heating or steam augmentation) or a coal
- fired EGU co
firing natural gas would have lower non
- CCS related auxiliary loads and, because the amount of CCS needed to comply with the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **136** of **763** standard would also be smaller, the CCS auxiliary loads would also be reduced. Therefore, we cannot identify an appropriate assumed auxiliary load to establish an equivalent net
- output based standard. In addition, many IGCC facilities (which could be used as an alternative technology for complying with the standard of per formance ; see section s IV.B and V.P below) have been proposed or are envisioned as co
-production facilities (i.e., to produce useful by
-products and chemicals along with electricity). As noted in the proposal, we have concluded that predicting the net electricity at these co
-production 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 combusti on turbine EGUs in a format that is similar to the current NSPS format for criteria pollutants. The default final standards establish a gross
- output -based standard. This allows owners/operators of new combustion turbines to comply with the CO 2 emissions standard under Part 60 using the same data currently collected under Part 75. 117 However, many permitting

117 Additionally, having an NSPS standard that is measured 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, more expensive***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **137** of **763** authorities commented persuasively that the environmental benefits of using net
- output -based standards can outweigh any additional complexiti es for particular units , and have indeed adopted net - output standards in recent GHG operating permits for combustion turbines . We expect this trend to continue and have concluded that it is appropriate to support the expanded use of net - output -based standa rds , and therefore are allowing 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 The procedures for requesting this alternative net
- output based standard require the owner or operator to petition the Administrator in writing to comply with the alternate applicable net - output -based standard . If the Administrator grants the petition, this election would be binding and would be the unit’s sole means of demonstrating compliance. Owners or operators complying with the net
- output -based standard must similarly higher accuracy monitoring could be required for both measurements. 118 Assuming a 3 percent auxiliary load for the NGCC sys tem.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **138** of **763** petition the Administrator to switch back to complying with the gross - output -based standard. 2. Useful Thermal Output For CHP units, useful thermal output is also used when 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 determining the emission rate. We proposed that 75 percent credit is the appropriate discount factor for useful thermal output, and we solicited comment on a range from two
- thirds to three
- fourths credit for useful thermal output in the proposal for newly constructed units and two
- thirds to one hundred percent credit in the proposal for modified and reconstructed units. The 75 percent credit was based on matching the emission rate , but not the overall emissions, of a hypothetical CHP unit to the proposed emission rate. Many commenters sai d that in order to fully account for the environmental benefits of CHP and to reflect the environmental benefits of CHP, the EPA should allow 100 percent of the useful thermal output from CHP units. Commenters noted that providing 100 percent credit for useful thermal output is consistent with the past practice of the EPA in the stationary combustion turbine criteria pollutant NSPS and state approaches for determining emission rates for CHP units.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **139** of **763** Based on further consideration and review of the comments submitte d, we are finalizing 100 percent credit for useful thermal output for all newly constructed, modified, and reconstructed CHP sources . We have concluded that this is appropriate because , at the same reported emission rate , a hypothetical CHP unit would have the same overall GHG emissions as the combined emission rate of separate heat and power facilities. Any discounting of useful thermal output could distort the market and discourage the development of new CHP units. Full credit for useful thermal output appropriately recognizes the environmental benefit of CHP. G. CO2 Emissions Only The air pollutant regulated in this final action is greenhouse gases. However, the standards in this rule are expressed in the form of limit s on only emissions of CO 2 , and not the other constituent gases of the air pollutant GHGs. 119 We are not establishing a limit on aggregate GHGs or separate emission limits for other GHGs (such as methane (CH 4 ) or nitrous oxide ( N 2O )) as other GHGs represent less than 1 percent of total estimated GHG emissions (as CO 2 e) from fossil fuel
- fired electric
119 As noted above, in the Endangerment Finding, the EPA defined the relevant “air pollution” as the atmospheric mix of six long
lived and directly
- emitted greenhouse gases: carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 ). 74 FR 66497.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **140** of **763** power generating units. 120 Notwithstanding this form of the standard, consistent with other EPA regulations addressing GHGs , the air pollutant regulated in this rule is GHGs . 121 H. Legal Requirements for Establishing Emission Standards 1. Introduction In the January 2014 proposal, we described the principal legal requirement for standards of performance under CAA section 111(b), which is that the standards of performance must consist of standards for emissions that reflect the degree of emission limitat ion achievable though the application of the “best system of emission reduction ... adequately demonstrated,” taking into account cost and any nonair quality health and environment impact and energy requirements . We noted that the D.C. Circuit has handed down numerous decisions that interpret this CAA provision, including its component elements, 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 clarifyi ng our interpretation in certain respects. We discuss our

120 EPA Greenhouse Gas Reporting Program; www.epa.gov/ghgreporting/ 121 See 77 FR 31257
- 30 (June 3, 2010). 122 79 FR 1430, 1462 (January 8, 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **141** of **763** interpretation below. 123 2. CAA Requirements and Court Interpretation As noted above , the CAA section 111 requirements that govern this rule are as follows: As the first step towards establishing standards of performance, the EPA “shall publish ... a list of categories of stationary sources ... [that] cause[], or contribute[] significantly to , air pollution which may reasonably be anticipated to endanger public health or welfare.” CAA s ection 111(b)(1)(A). Following that listing, the EPA “shall publish proposed regulations, establishing federal standards of performance for new sources within such category” and then “promulgate ... such standards” within a year after proposal. CAA
s ection 111(b)(1)(B). The EPA “may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standa rds.” CAA s ection 111(b)(2). The term “standard of performance” is defined to “mean[] a standard for emissions of air pollutants which reflects the
123 We also discuss our interpretation of the requirements 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 and applications of these requirements in the two rulemakings 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, which are expected to have lengthy useful lives, should include, at a minimum, the most advanced pollution controls available, but for existing sources, the additional costs of retrofit may render those controls too expensive .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **142** of **763** degree of emission limitation achievable through the application of the best system of emission reduc tion which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” CAA s ection 111(a)(1). As noted in the January 2014 proposal, Congress first 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 amended it again in the 1990 CAAA to largely rest ore the definition as it read in the 1970 CAAA . It is in the legislative history for the 1970 and 1977 CAAAs that Congress primarily addresse d the definition as it read at those times , and that legislative history provides guidance in interpreting this provision. 124 In addition, the D.C.

124 In the 1970 CAAA, Congress defined “standard of performance,” under §111(a)(1), as

— a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the app lication of the best system of emission reduction which (taking into account the cost of achieving such reduction) the Administrator determines has been adequately demonstrated. In the 1977 CAAA, Congress revised the definition to distinguish among different types of s ources, and to require that for fossil fuel
- fired sources, the standard (i) be based on, in lieu of the “best system of emission reduction ... adequately demonstrated,” the “best technological system of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **143** of **763** Circuit has reviewed rulemakings under CAA section 111 on numerous occasions during the past 40 years, handing down decisions dated from 1973 to 2011, 125 through which the Court has developed a body of case law that interprets the term “standard of performance.” 3. Key Elements of Interpretation By its terms, the definition of “standard of performance” under CAA section 111(a)(1) provides that the emission limits that the EPA promulgates must be “achievable” by application of
a “ system of emission reduction ” that the EPA determines to be continuous emission reduction ... adequately demonstrated;” and (ii) require a percentage reduction in emissions. In addition, in the 1977 CAAA, Congress expanded the parenthetical requirement that the Administrator consider the cost of achieving the reduction to also require the Administrator to consider “any nonair quality health and environment impact and energy requirements.” In the 1990 CAAA, Congress agai n revised the definition, this time repealing the requirements that the standard of performance be based on the best technological system and achieve a percentage reduction in emissions, and replacing those provisions with the terms used in the 1970 CAAA version of §111(a)(1) that the standard of performance be based on the “best system of emission reduction ... adequately demonstrated.” This 1990 CAAA version is the current defi nition. Even so, because parts of the definition as it read under the 1977 CAAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative history, and the interpretation in the case law, of those parts of the definition in the case law remain relevant to the definition as it reads today. 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).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **144** of **763** the “best” that is “adequately demonstrated,” “taking into account ... cost ... nonair quality health and environmental impact and energy requirements.” The D.C. Circuit has stated that , in determining the “best” system, the EPA must also take into 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 factors. 128 , 129 Our overall approach to determining the BSER, which incorporates the various elements, is as follows: First, the EPA identif ies the “system[s] of emission reduction” that have been “adequately demonstrated” for a particular source category. Second, the EPA determine s the “best” of these systems after evaluating extent of emission reductions, costs, any nonair health and environmental impacts, and energy requirements. And third, the EPA select s an achievable standard for emissions
- here, the emission rate
- based on the performance of the BSER.
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. Circuit’s case law appears to treat them as part of the “best” determination. See Sierra Club v. Costle, 657 F.2d at 325
- 26. It does not appear that those two approaches would lead to different outcomes. In this rule, the EPA is following the D.C. Circuit case law and treating the factors as part of the “best” determination.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **145** of **763** The remainder of this subsection discusses the 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 emission reduction ... adequately demonstrated.” For the reasons discussed below, for the various types of newly construct ed , modified, and reconstructed sources in this rulemaking, the EPA focused on efficient generation, add- on controls , efficiency improvements , and clean fuels as the systems of emission reduction. An “adequately demonstrated” system, according to the D.C. Circuit, is “one which has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to
s erve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.” 130 It does not mean that the system “must be in actual routine use somewhere.” 131 Rather, the Court has said, “[t]he Administrator may make a pro jection based on existing technology, though that projection is subject to the restraints of reasonableness and

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 Senate and House bills and reports from which the language in CAA section 111 grew).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **146** of **763** cannot be based on ‘crystal ball’ inquiry.” 132 Similarly, the EPA may “hold the industry to a standard of improved design and operational advances , so long as there is substantial 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), s tandards of performance under CAA section 111(b) are applicable immediately after the effective date of their promulgation (1) Technical feasibility of the best system of emission reduction . As the January 2014 proposal indicates, the requirement that the standard for emissions be “achievable” based on the “best system of emission reduction ... adequately demonstrated” indicates that one of the requirements for the technology or other measures that the EPA identifies as the BSER is that the measure must be technically feasible. See 79 FR 1430, 1463 (January 8, 2014). b. “Best” . In determining which adequately demonstrated system of emission reduction is the “best,” the EPA considers the foll owing factors:

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
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– Do Not Cite, Quote or Release During Review *** Page **147** of **763** (1) Costs . Under CAA section 111(a)(1), the EPA is required to take into account “the cost of achieving” the required emission reductions. As described in the January 2014 proposal, 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 EPA may not adopt a standard the cost of which would be “exorbitant,” 136 “greater than the industry could bear and survive,” 137 “excessive,” 138 or “unreasonable.” 139 For convenience, in th is rulemaking, we use ‘ reasonableness ’ to describe costs well within the bounds established by this jurisprudence . 140

135 79 FR at 1464 (January 8, 2014). 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 legislative history of section 111. The 1977 House Committee Report noted: In the [1970] Congress [ sic : Congress’s] view, it was only right that the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business. 1977 House Committee Report at 184. Similarly, the 1970 Senate Committee Report state d:

The implicit consideration of economic factors in determining whether technology is “available” should not affect the usefulness of this section . The overriding 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **148** of **763** The D.C. Circuit has indicated that the EPA has substantial discretion in its consideration of cost under section 111(a). In several cases, the Court upheld standards that entailed significant costs , consistent with Congress’s view that “the costs of applying best practicable control technology be considered by the owner of a large new source of pollution 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 imposing controls
on SO 2 emissions from coal
- fired power plants when the ”cost of

their construction is seen by the committee as the most effective and, in the long run, the least expensive approach. S. Comm. Rep. No. 91
- 1196 at 16. Some commenters asserted that we do not have authority to revise the cost standard as established in the case law, e.g., “exorbitant,” “excessive,” etc., to a “reasonableness” standard that may be considered less protective of the environment. We agree that we do not have authority to revise the cost standard as established in the case law, and we are not attempting to do so here. Rather, our description of the cost standard as “reasonableness” is intended to be a convenient term for referring to the cost standard as established in the case law. 141 1977 House Committee Report at 184. 142 The costs for these standards were described in the rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 (March 21, 1972).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **149** of **763** the new controls ... is substantial ”) . 143 Moreover, section 111(a) does not provide specific direction regarding what metric or metrics to use in considering costs, again affording the EPA considerable discretion in choosing a means of cost consideration. 144 As discussed below, the EPA may consider costs on both a
source - specific basis and a sector
-wide , regional, or nationwide basis. The EPA is finding here that whether costs are considered
on a source - specific basis, an industry/national basis, 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 environmental impact” in determin ing the BSER. As the D.C. Circuit has explained, this requirement makes explicit that a system cannot be “best” if it does more

143 Indeed, in upholding the EPA’s consideration of costs under the provisions of the Clean Water Act authorizing technology
based standards based on performance of a best technology taking costs into account, courts have also noted the substantial discretion delegated to the EPA to weigh cost considerations 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). 144 See, e,g., Husqvarna AB v. EPA, 254 F. 3d 19 5, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a specific method of cost analysis, EPA may make a reasoned choice as to how to analyze costs).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **150** of **763** harm than good due to cross -media environmental impacts. 145 The EPA has carefully considered such cross
-media impacts here, in particular potential impacts to underground sources of drinking water posed by CO 2 sequestration, and water use necessary to operat e carbon capture systems . See sections V. N and O below. (3) Energy considerations . Under CAA section 111(a)(1), the EPA is required to take into account “energy requirements.” As discussed below, the EPA may consider energy requirements on both a source - specific basis and a sector
-wide , region
-wide, or nationwide basis. Considered on a source
- specific basis, “energy requirements” entail , for example, the impact, if any, of the system of emission reduction on the source’s own energy needs . In this rulemaking, as discussed below in section V.O.3 , the EPA considered the parasitic load requirements of partial CCS . The EPA is finding here that whether energy requirements are considered on a source
- specific basis, an industry/national basis, or both, they are reasonable . See section s 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 identify the amount of emissions from the category of
145 Portland Cement v. EPA, 486 F. 2 d 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 determination).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **151** of **763** sources or the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” 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 statutory words “best ... system” which would not i ncorporate the amount of air pollution as a relevant factor to be weighed when determining 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 explicitly incorporates the concept of reducing emissions, supports 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 emission reductions, the EPA has the discretion to do so, on grounds that either the term “system of emission
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 system” to read, “best technological system.” As noted above, the 1990 CAAA deleted “technological,” and the reby returned the phrase to how it read under the 1970 CAAA. The court’s interpretation of this phrase in Sierra Club v. Costle to require consideration of the amount of air emissions reductions remains valid for the phrase “best system.” 147 See also NRDC v . EPA, 479 F. 3d 875, 88 0 (D.C. Cir. 2006) (“best performing” source for purposes of CAA section 112 (d)(3) is source with the lowest emission levels).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **152** of **763** reduction” or the term “best” may reasonably be read to allow that discretion. ( 5 ) Sector - or nationwide component of factors in determining the BSER . 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 factors it is required to consider on a national or regional level and over 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 savings,” 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 bil ls illustrate very clearly that Congress itself was using a long
- term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111. 149 The Court has upheld rules that the EPA “ju stified ... in terms of the policies of the Act,” including balancing 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)
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).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **153** of **763** yet does so at reasonable costs without significant energy penalties.... By achieving a balanced coal demand within the utility sector and by promoting the 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 Some commenters objected that this case law did not allow 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 consideration of cost, non - air quality impacts , and energy requirements reflect source
- specific impacts, as well as (for some considerations) impacts that are sector -wide, regional , or national . See section V.H.6 below.
c. Achievability of the standard for emissions . In the January 2014 proposal, the EPA recognized that the first element of the definition of “standard of performance” is that “the emission limit [ i.e ., the ‘standard for emissions’] that the EPA promulgates must be ‘achievable’” based on performance of the BSER. 79 FR 1430, 1463 (January 8, 2014). According to the D.C.
150 Sierra Club v. Costle , 657 F.2d at 327
- 28 (quoting 44 Fed. Reg. at 33,583/3
- 33,584/1). In the January 2014 proposal, we explained that although the D.C. Circuit decided Sierra Club v. Costle before the Chevron case was decided in 1984, the D.C. Circuit’s decision could be justified under either Chevron step 1 or 2. 79 FR 1430, 1466 (January 8, 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **154** of **763** Circuit, a standard for emissions is “achievable” if a technology can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard. 151 Moreover, according to the Court, ”[a]n achievable standard is one which is within the realm of the adequately demonstrated system’s efficiency and which, while not at a level that is purely theoretical or experimental , need not necessarily be routinely achieved within the industry prior to its adoption.” 152 To be achievable, a standard “must be capable of being met under most adverse conditions which can reasonably be expected to recur and which are not or cannot be take n into account in determining the ‘cost of compliance.’” 153 To show that a standard is achievable, the EPA must “(1) identify variable conditions that might contribute to the amount of expected emissions, and (2) establish that the test data relied on by the agency are representative of potential industry
-wide performance, given the range of variables that affect the

151 Portland Cement , 486 F. 2d at 391
- 92. Some commenters stated that the EPA’s analysis of the requirements fo r “standard of performance,” including the BSER, attempted to eliminate the requirement that the standard for emissions must be “achievable.” We disagree with this comment. As just quoted, the EPA’s analysis recognizes that the standard for emissions 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).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **155** of **763** achievability of the standard.” 154 In section s V. J and IX.D below, we show both that the BSER for new steam generating units and combustion turbines is technically feasible and adequately demonstrated, and 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 variables that affect achievability . d . Expanded use and development of technology . In the January 2014 proposal, we noted that the D.C. Circuit has made clear that Congress intended for CAA section 111 to create incentives for new technology and therefore that the EPA is required to consider technological i nnovation as one of the factors in determining the “best system of emission reduction.” 155 The Court grounded its reading in the statutory text. 156 In

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, i t may be sufficient to “generalize from a sample of one when one is the only available sample, or when that one is shown to be representative 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). 155 See 7 9 FR 1430, 1465 (January 8, 201 4 ) , Sierra Club v. Costle , 657 F.2d at 34 6
- 4 7. 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 EPA must weigh are***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **156** of **763** addition, in the January 2014 proposal, we noted that the Court’s interpretation finds additional support in the legislative history . 157 We also explained that the legislative history identifies three different ways that Congress designed CAA section 111 to authorize standards of performance that promote technological improvement: (i) the development of technology that may be treated as the “best system of emission reduction . . . adequately demonstrated” under section 111(a)(1); (ii) the expanded use of the best demonstrated technology; and (iii) the development of emerging technology. 158 Even if the EPA were not required to consider technological innovation as part of its determination of the BSER, it would be reasonable for the EPA to consider it, either because technological innovation may be considered an element of the term “best,” or because the term “best system of emission reduction” is ambiguous as to whether technological innovation may be considered . The interpretation is likewise consistent broadly defined and include within their ambit subfactors such as technological innovation. ”). 157 See 79 FR 1430, 1465 (January 8, 2014) (citing S.Rep. 91
- 1196 at 16 (1970)) (“Standards of performance should provide an incentive for industries to work toward constant improvement in techniques for preventing and controlling emissions from stationary source s”); 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 use of available technology and to stimulate the development of new technology”). 158 79 FR at 1465 (citing case law and legislative history).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **157** of **763** with the evident purpose of section 111 (b) to require new sources to maximize emission reductions using state - of - the - art means of control. Commenters state d that the requirement to consider technological innovation does not authorize the EPA to identify as the BSER a technology that is not adequately demonstrated. The proposal did not, and we do not in this final rule, 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 incentivizing technological innovation or development.
e . Agency discretion . As discussed in the January 2014 proposal, the D.C. Circuit has made clear that the EPA has broad discretion in determining the appropriate standard of performance under the definition in CAA section 111(a)(1), quoted above. Specifically, in Si erra 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 discretion to weigh diffe rent factors in setting the standard.” 160 In Lignite Energy Council v. EPA, 198 F.3d 930

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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **158** of **763** (D.C. Cir. 1999), the Court reiterated:

Because section 111 does not set forth the weight that should be assigned to each of these factors, we have granted the agency a great degree of discretion in balancing them.... EPA's choice [of the ‘best system’] will be sustained unless the environmental or economic costs of using the technology are exorbitant.... EPA [has] considerable discretion under section 111. 161 f . Lack of requirement that standard be able to be met by all
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 constructed in the absence of that standard. As described in the January 2014 proposal, the EPA based this view on (i) the legislative history of CAA section 111, read in conjunction with the legislative history of the CAA as a whole; (ii) case law under analogous CAA provisions; and (iii) long
- standing
specific weight the Administrator should assign to the statutory elements, “the Administrator is free to exercise [her] discretion” in promulgating an NSPS). 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) (EPA did not err in its final balancing because “neither RCRA nor EPA’s regulations purports to assign any particular weight to the factors listed in subsection (a)(3). That being the case, the Administrator was free to emphasize or deemphasize particular factors, constrained only by the requirements of reasoned agency decision making.”).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **159** of **763** precedent in the EPA rulemakings under CAA section 111. 162 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 reasons described there. We note that as a practical matter, in this rulemaking, the issue of whether all new steam- generating sources can implement partial
- capture CCS is largely dependent on the geographic scope of geologic sequestration sites. As discussed below in section V.M , geologic sequestration sites are widely available, and a steam
- generating plant with partial CCS that is sited near an area that is suitab le for geologic sequestration can serve demand in a large area that may not have sequestration sites available. In any event, the standard of 1 , 400 lb CO 2 /MW
- g that we promulgate in this final rule can be achieved by new steam generating EGUs

– including new utility boilers and IGCC units
- through co - firing with natural gas in lieu of installing partial CCS, which moots the issue of the geographic availability of geologic sequestration . g. EPAct05 . The Energy Policy Act of 2005 (“EPAct0 5”) authorizes assistance in the form of grants, loan guarantees, as well as Federal tax credits for investment in “clean coal technology.” Sections 402(i), 421(a), and 1307(b) (adding section 48A(g) to

162 79 FR 1430, 1466 (January 8, 2014) .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **160** of **763** the Internal Revenue Code (“IRC”)) address the extent to which information from clean coal projects receiving assistance under the EPAct05 may be considered by the EPA in determining what is the best system of emission reduction adequately demonstrated. Section 402(i) of the EPAct05 limits the use of information from facilities that receive assistance under EPAct05 in CAA section 111 rulemakings: No technology, or level of emission reduction, solely by reason of the use of the technology, or the achievement of the emission reduction, by 1 or more facilities receiving assistance under this Act, shall be considered to be adequately demonstrated [] fo r purposes of section 111 of the Clean Air Act .... 163 IRC section 48A(g) contains a similar constraint concerning the use of technology or level of emission reduction from EGU facilities for which a tax credit is allowed: No use of technology (or level of emission reduction solely by reason of the use of the technology), and no achievement of any emission reduction by the demonstration of any technology or performance level, by or at one or more facilities with respect to which a credit is allowed under this section, shall be considered to indicate that the technology or performance level is adequately demonstrated [] for purposes of section 111 of the Clean Air Act ....

163 Codified at 42 U.S.C. 15962(a). EPAct05 section 421(a) similarly states: “No technology , or level of emission reduction , shall be treated as adequately demonstrated for purpose [sic] of section 7411 of this title , ... solely by reason of the use of such technology , or the achievement of such emission reduction , by one or more facilities receiving assistance under section 13572(a)(1) of this title”.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **161** of **763** The EPA specifically solicited comment on its interpretation of these provisions. 79 FR 10750 (Feb. 26, 2014)(Notice of Data Availability). With respect to EPAct05 sections 402(i) and 421(a), the EPA proposed that these provisions barred consideration where EPAct05
- assisted facilities were the sole support for the BSER determination, but that these sources could support a BSER determination so long as there is additional evidence supporting the determination. 164 In addition, the EPA viewed the two prohibitions as relating 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 provided by sections 402(i) and 421(a)

– to mean that use of technol ogy, or emission performance, from a facility for which the credit is allowed cannot, by itself, support a finding that the technology or performance level is adequately demonstrated, but the 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 this section” as referring to the entire phrase “use of technology (or level

164 Technical Support Document p. 6. 165 Id. 166 Id. p. 13.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **162** of **763** of emission reduc tion...) and [] achievement of any emission reduction..., by or at one or more facilities.” Thus, if technology A received a tax credit, but technology B at the same facility 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 interpretation would allow it to support a BSER determination even where EPAct05 facility information comprised 99 percent of the supporting information for a BSER determination because that determination would not be based “solely” on EPAct05 sources. These commenters urged EPA to conclude that a determination “solely” on the basis of information from EPAct05
- assisted facilities is any determination where “but for” that information, the EPA could not justify its chosen standard as the BSER. 168 Other commenters argued that the provisions bar the EPA from all consideration of EPAct05 facilities when determining that a technology or level of performance is adequately demonstrated. In this final rule, the EPA is adopting the interpretations of all three provisions that it proposed, largely for the reasons previously advanced. The EPA thus interprets these
167 Id. p. 14. 168 Comments of AFPM/API p. 46.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **163** of **763** provisions to preclude the EPA from relying solely on the experience of facilities that received DOE assistance, but not to preclude the EPA from relying on the experience of such facilities in conjunction with other information. This reading of sections 402(i) and 421(a) is consistent with the views of the only court to date to consider the matte r. 169 The EPA notes that the extreme hypothetical posed in the comments (where EPA might avoid a limitation on its consideration of EPAct05
- assisted facilities by including a mere scintilla of evidence from non
-EPAct05 facilities) is not presented here, where the principal evidence that partial post combustion CCS is a demonstrated and feasible technology comes from sources which received no assistance of any type 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 piece of evidence may be a necessary, or “but for,” cause without being 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 federal ly- funded facilities. 42 U.S.C. § 15962(i) . In other words, such technology might be adequately demonstrated if that determination is based at least in part on non
- federallyfunded facilities”)(emphasis original).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **164** of **763** sufficient, or “sole,” cause. 170 Nonetheless, if the “but for” test were applicable here, the available evidence would satisfy it. Other commenters took the extreme position that the EPAct05 provisions bar all consideration of a facility’s existence 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 technology. For the same reason, the EPA does not accept some commenters’ suggestion that sections 402(i), 421(a), and 48A(g) preclude the EPA from considering NETL’s cost projections for CCS, which base cost estimates on up
- to - date vendor quotes reflecting costs 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 decision, the decision of the Court would have been different “but for” the assent of Justice A or Justice B, who were in the majority. But it would be incorrect to say that the assent o f Justice A was the “sole” reason for the outcome, when the decision also required the assent of Justice B. 171 Supplemental Comments of Murray Energy (comment 9498) p. 11. 172 With respect to sections 402(i) and 421(a), commenters fail to reconcile their reading of the statute with the Act’s grammatical structure, as explained in detail in chapter 2 of the Response - to - Comment document. One commenter supported its reading by adding suggested text to the statutory language, a highly disfavored form of statutory construction. Comments of UARG, p.124 n.38. With respect to section 48A(g), commenters misread the phrase “considered to indicate,” and do not explain how their reading of all three provisions together is tenable.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **165** of **763** CCS technology being utilized at the Boundary Dam Unit #3 faci lity (a facility receiving no assistance under EPAct05), but also considers that to
-be -built plants will no longer be first
of - a kind. See generally section V.I.2 below. Commenters suggest that the EPAct05 requires that the EPA treat future plants as “fir st of a kind” when projecting costs, as if EPAct05 facilities simply did not exist. This reading is contrary to the text of the provisions, which as noted, relates specifically to a source’s performance and operation (whether a technology is demonstrated, and the level of performance achieved by use of technology ), not to sources’ existence. NETL’s cost projections, on the other hand, merely acknowledge the evident fact that CCS technologies exist, and reasonably project that they will continue to develop. See section V.I.2. The NETL cost estimates, moreover, are based on vendor quotes for the CCS technology 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 finds that a new highly
- efficient SCPC EGU implementing partial post combustion CCS is the best system of emission reduction adequately demonstrated and is doing so based in greater part on performance of facilities receiving no assistance under EPAct05, and on other information likewise not having any connection to***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **166** of **763** EPAct05 assistance . The corroborative information from EPAct05 facilities, though supportive, is not necessary to the EPA’s findings. I. Severability This rule has numerous components , and the EPA intends that they be severable from each other to the extent that they funct ion separately. For example, the EPA intends that each set of BSER determination s and standards of performance in this rulemaking be severable from each other set. That is , the BSER determination and standard of performance for newly constructed fossil fue l - fired electric utility steam generating units are severable from all the other BSER determinations and standards of performance, and the same is true for the BSER determination and standard of performance for modified fossil fuel
- fired electric utility s team generating units, and so on. It is reasonable to consider each set of BSER determination and standard of performance to be severable from each other set of BSER determination and standard of performance because 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 should not be affected. J. Certain Projects under Development***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **167** of **763** In the January 2014 proposal, the EPA indicated that the proposed Wolverine EGU project (Rogers City, Michigan) appeared to be the only fossil fuel
- fired steam generating unit that was currently under development that may be capable of “c ommencing construction” for NSPS purposes at the time of the proposal. See 79 FR 1461. The EPA also acknowledged that the Wolverine 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 standards, if the Wolverine project remains under development and has not either commenced construction or been canceled, we anticipate d proposing a standard of performance specifically for that faci lity. Additional discussion of the approach can be found in the proposal or in the technical support document in the docket entitled “Fossil Fuel
- Fired Boiler and IGCC EGU Projects under Development: Status and Approach.” In December 2013

– after the propo sed action was signed, but before it was published

– Wolverine Power Cooperative announced that it was cancelling construction of the proposed coal - fired power plant in Rogers City, MI. 173 Therefore, we are not finalizing the proposed exclusion for that proj ect.

173 “Wolverine ends plant speculation in Ro gers City”, The Alpena News, December 17, 2013.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **168** of **763** In the January 2014 proposal, the EPA also identified two other fossil fuel
- fired steam generating EGU projects that, as currently designed, would not meet the proposed 1,100 lb CO 2 /MWh emissions standard

— the Plant Washington project in 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 represented that the projects have commenced construction for NSPS purposes and, thus, would not be new sources subject to the proposed or final NSPS. Based solely on the developers’ representations, the EPA indicated that those projects, if ultimately fully constructed, would be existing sources, and would thus not be subject to the standards of performance in this final action. T o date, neither developer has sought a formal EPA determination of NSPS applicability. As we specified in the January 2014 proposal

– and we reiterate here
- if such an applicability determination concludes that ei ther the Plant Washington (GA) project or the Holcomb 2 (KS) project did not commence construction prior to January 8, 2014 (the publication of the January 2014 proposal), then the project should be situated similarly to the disposition the EPA proposed fo r the Wolverine project. Accordingly, the EPA is finalizing in this http://www.thealpenanews.com/page/content.detail/id/527862/Wolve rine
- ends -plant - speculation
- in
-Rogers - City.html?nav=5004***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **169** of **763** action that if it is determined that either of these 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 January 2014, Power4Georgians (P4G), the Plant Washington developer, 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 believe that the binding contracts are sufficient to constitute commencement of construction for purposes of the NSPS program , so that they are existing rather than new sources for purposes of this rule . 174 Public comments submitted by Tri
- State Generation and Transmission Association and Sunflower Electric Power Corporation, the developers of the Holcomb 2 project, discussed the cost incurred in the development of the project . They also indicated they had awarded contract s for the turbine/generator purchase and had negotiated a rail
- supply agreement that provides for the delivery of fuel to the proposed Holcomb 2 site . The developers did not, however, explicitly characterize the construction status of the project. 175 Other groups submitted

174 Docket entry: EPA- HQ - OAR- 2013
- 0495
- 9403 175 Docket entry: EPA- HQ - OAR- 2013
- 0495
- 9 599***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **170** of **763** comments contending that neither project has actually commenced construction. In October 2013, the Kansas Supreme Court invalidated the 2010 air pollution permit granted to Sunflower Electric 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 Supreme Court held had been overlooked in the initial permitt ing determination . 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 the proposed Holcomb 2 site. In October 2014, the Plant Washington project was given an 18
-month air permit extension by the Georgia Environmental Protection Division (EPD). However, as with the Holcomb expansion project, the EPA is unaware of any physi cal construction that has taken place at the proposed Plant

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- coal project
- air
-permit/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **171** of **763** Washington site and a recent audit of the project described it as “dormant”. 177 Based on this information, it appears that these sources have not commenced construction for purposes of s ection 111 (b) and therefore would likely be new sources should they actually be constructed. As noted above, the EPA propose d that, if these projects are determined to not have commenced construction for NSPS purposes prior to the publication of the proposed rule, they will be addressed in the same manner proposed for the Wolverine project. 79 FR 1461. We are finalizing that proposal here. However, because these units may never actually be fully built and operated, we are not promulgating a standard of performance at this time because such action may prove to be unnecessary. 178

177 http://www.macon.com/2015/06/23/3811798/audit
- sandersville
coal -plant.html 178 In the proposed emission guidelines for existing EGUs, the EPA did not include estimates of emissions for either Plant Washington or the Holcomb 2 unit in baseline data used to calculate proposed state goals for Georgia and Kansas. It appear s that the possibility of these plants actually being built and operating is too remote. If either unit eventually seeks an applicability determination and that unit is determined to be an existing source, and there is reliable evidence that the source wil l operate, then the source will be subject 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 baseline data so as to include the unit. Guidance for adjustment of state goals is provided i n the record for the EPA’s final CAA section 111(d) rulemaking.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **172** of **763** There is one possible additional new EGU , the Two Elk project in Wyoming. In the January 2014 proposal we relied on developer statements and state acquiescence that the unit had commenced construction for NSPS purposes before January 8, 2014. [CITE] We did not, therefore, propose any special sec tion 111(b) standard for the project. Some commenters maintained that a continuous program of construction at the facility has not been maintained and that if the plant i s ultimately constructed, it should be classified as a new source under CAA section 11 1(b). These comments were not specific enough to change EPA’s view of the project fo r purposes of this rulemaking. We accordingly continue to rely on developer statements that this facility has commenced construction and would not be a new source for purpo ses of this proceeding. **IV. Summary of Final Standards for Newly Constructed, Modified, and Reconstructed Fossil Fuel**  **- fired**  **Electric Utility Steam Generating Units**  This section sets forth the standards for newly constructed, modified, and reconstructed steam generating units (i.e., utility boilers and IGCCs). We explain the rationale for the final standards in Sections V (newly constructed steam generating unit), VI (modified steam generat ing units), and VII (reconstructed steam generating units). A. Applicability Requirements and Rationale***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **173** of **763** We generally refer to fossil fuel
- fired electric utility generating units that would be subject to an emission standard in this rulemaking as “affect ed” or “covered” sources, 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 “recon structed” sources as defined under the provisions of CAA section 111 and the EPA’s regulations. This section discusses applicability for newly constructed, modified, and reconstructed steam generating units. 1. General Applicability C riteria The EPA is finalizing applicability criteria for new, 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 criteria, relevant comments , and final applicability criteria specific to newly constructed, modified, and rec onstructed steam generating 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 MMBtu/h heat***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **174** of **763** input of fossil fuel; (2) be constructed for the purpose of supplying, and actually supply, more than one
- third of its potential net
- electric output capacity to any utility power distribution system (that is, to the grid) for sale on an annual basis ; (3) be constructed for the purpose of supplying, and actually supply, more than 219,000 MWh net
- electric output to the grid on an annual basis; and (4) combust over 10 percent fossil fuel on a heat i nput basis over a 3
- year average. At proposal , applicability was determined based on a combination of design and actual operating conditions that could change annually depending on the proportion and the amount of electricity actually sold and on the propo rtion of fossil fuel s 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 criteria and would be identical to the applicability requ irements in subpart Da. First, we proposed electric sales criteria that the source be constructed for the purpose of selling more than one
- third of their potential electric output and more than 219,000 MWh to the grid on an annual basis, regardless of the actual amount of electricity sold (i.e., we did not include the applicability criterion that the unit actually sell the specified amount of electricity on an annual basis). In addition, we proposed a base***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **175** of **763** load rating criterion that the source be capable of combusting more than 250 MMBtu/h of fossil fuel , regardless of the actual amount o f fossil fuel burned (i.e., we did not include the fossil fuel - use criterion that an EGU actually combust 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 the final applicability criteria would be consistent for newly constructed, reconstructed, and modified units. The proposed broad applicability criteria would stil l not have included boilers and IGCC units that were constructed for the 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 units are not covered under subpart Da (the utility boiler and IGCC EGU criteria pollutant NSPS) but are instead covered as industrial boilers under subpart Db (industrial, institutional, and commercial boilers NSPS) or subpart KKKK (the combustion turbine criteria pollutant NSPS). We solicited comment on whether , to avoid implementation issues related with different interpretations of “ constructed for the purpose, ” the total and percentage electric sales criteria should be recast to be based on permit conditions. The “constructed for the purpose” language was included in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **176** of **763** original subpart Da rulemaking. At that time, the vast majority of new steam generating units were clearly base load units. The “constructed for the purpose” language was intended to exempt industrial CHP units. These units tend to be relatively small and were not the focus of the rulemaking. In addition, units not meeting the electric sales applicability criteria in subpart Da would be covered by other NSPS so there is limited regu latory 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 the ir original intent (i.e., the purpose for which they were constructed) in an attempt to avoid applicability under section 111(d) requirements. Consequently , there could be a regulatory incentive for owners/operators to circumvent the CO 2 NSPS applicability. For units that avoid coverage, there would also be a corresponding environmental impact. For example, an owner/operator of a new unit could initially request a permit restriction to limit electric sales to less than one - third of potential annual electric output, but amend the operating permit shortly after operation has commenced to circumvent the intended applicability. Many existing units were initially built with excess capacity to account for projected load growth and were intended to sell more than one third of their potential electric output. However, due to***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **177** of **763** various factors (lower than expected load growth, availability of other lower cost units, etc .) , certain units might have sold less than one - third of their potential electric output, at least during their initial period of operation . Therefore, the EPA has concluded that determining applicability based on whether a unit is “ constructed for the purpose of supplying one
- third or more of its potential electric output and more than 219,000 MWh as net - electric sales” (emphasis added) could create applicability uncertainty for both the regulated community and regulators. In addition, we have concluded that appl icability based on actual operating conditions (i.e., actual electric sales) is not ideal because applicability would not be known prior to determining compliance and could change annually. This action finalizes applicability criteria based on design characteristics and federally enforceable permit restrictions included in each individual permit. Based on restrictions, if any, on annual total electric sales 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 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 approach is***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **178** of **763** equivalent to , but clearer than , the existing language used in subpart Da. In addition, we have concluded that it is important for both the 111(b) and 111(d) requirements for electric
- only steam generating units that the permit restriction limiting annual electric sales be included in both the original and current operating permit. Without th is restriction, existing units could avoid obligations under state plans developed as part of the 111(d) program by amending their operating permit to limit total annual electric sales to one - third of potential electric output. These units would not be subject to any GHG NSPS requirements because they would not meet the 111(b) or 111(d) applicability criteria and , at this time, there is no NSPS that would cover these units. As described in S ection 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 that: (1) has a base load rating greater than 260 GJ/h ( 250 MMBtu/h ) of fossil fuel (either alone or in combination with any other fuel) and (2) serve s a generator capable of supplying more than 25 MW
- net to a utility distribution system (i.e., for sale to the grid). However, we are not establishing final CO 2 standards fo r certain EGUs. These include: (1) steam generating units and IGCC units that are currently subject to
- and have been continuously***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **179** of **763** subject to
- a federally enforceable permit limiting annual electric sales to one - third or less of their potential electric output (e.g., limiting hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less; (2) units subject to a federally enforceable permit that limits the use of fossil fuels to 10 percent or 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 than the ir design efficiency times their potential electric output , or to no more than 219 ,000 MWh, whichever is greater. 2. Applicability Specific to Newly Constructed S team 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 performance under this section which will be applicable to such source. Accordingly, for purposes of this rule, a newly constructed steam generating EGU is a unit that fits the definition and applicability criteria of a fossil fuel
- fired steam generating EGU and commences construction on or after Janua ry 8, 2014, which is the date that the proposed standards were published for those sources (see 79 FR 1430).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **180** of **763** 3. Applicability Specific to Modified S team Generating Units In CAA section 111(a)(4 ) , a “modification” is defined as “any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” The EPA, through regulations, has determined that certain types of changes are exempt from consideration as a modification. 179 For purposes of this rule, a modified steam generating EGU is a unit that fits the definition and applicability criteria of a fossil fuel
- fired steam generating EGU and that modifies on or after June 18, 2014, which is the date that the proposed standards were published for those sources (see 79 FR 34960). 4. Applicability Specific to Reconstructed S team Generating Units The NSPS general provisions (40 CFR part 60 , s ubpart A) provide that an existing source is considered a new source if it undertakes a “reconstruction,” which is the replacement of components of an existing facility to an extent that : (1) the fixed capital co st of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a

179 40 CFR 60.2, 60.14(e)***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **181** of **763** comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards. 180 For purposes of this rule, a reconstructed steam generating EGU is a unit that fits the definition and applicability criteria of a fossil fuel
- fired steam generating EGU and that reconstructs on or after June 18, 2014, which is the date that the proposed standards were publishe d for those sources (see 79 FR 34960). B. Best System of Emission Reduction 1. BSER for Newly Constructed S team Generating Units In the January 2014 proposal, the EPA proposed that highly efficient new generation technology implementing partial CCS is the BSER for GHG emission s from new steam generating EGUs . (See generally 79 FR 1468
- 1469 . ) In this final action, the EPA has determined that the BSER for newly constructed steam generating units is a new highly efficient supercritical pulverized coal (SCPC) boiler implementing partial CCS technology to the extent of removal efficiency that meets a final emission limitation of 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 greater detail later in this preamble, is in response to public comments and

180 40 CFR 60.15.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **182** of **763** reflects both a re - examination of the potential BSER technologies and the most recent, reliable information regarding technology costs . A newly constructed fossil fuel
- fired supercritical utility boiler will be able to meet the final standard by implementing post - combustion carbon capture treating a slip
- stream of the combustion flue gas. Alternative potential compliance paths are to build a new IGCC unit and co
- fire with natural gas (or use pre - combustion carbon capture on a slip
stream), or for a supercritical utility boiler to co
- fire with natural gas. The EPA of course realizes that the final standard of performance (1,400 lb CO 2 /MWh
- g) differs from the proposed standard (1,100 lb CO 2 /MWh
- g). The EPA notes further , however, that the methodology for determining the final standard of performance is identical to that at proposal

– determin ing that a new highly efficient generating technology implementing some degree of partial CCS is the BSER, with that degree of implementation being determined based on the reasonableness of costs. A key means of assessi ng the reasonableness of cost at proposal was comparison of the levelized cost of electricity (LCOE) with that of other dispatchable, base load non -NGCC generating options . We have maintained that approach in identifying BSER for the final standard. Applying this methodology to the mo st recent cost information has led the EPA***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **183** of **763** to adopt the final standard of performance of 1,400 lb CO 2 /MWh
- g. See section V. H at Table 8. This final standard reflects the level of emission reduction achievable by a highly efficient SCPC implementing the de gree of partial CCS that remains cost comparable to the other non -NGCC dispatchable base load generating options. The BSER for newly constructed steam generating EGUs 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 technology

– either alone or implementing partial CCS

– is not part of the BSER, but rather is a viable alternative compliance option. As noted at proposal, a BSER typically advances performance 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 s ection III.H.3.d above. For these reasons, the EPA at proposal voiced concerns about adopting standards that would allow an IGCC to comply without utilizing CCS for slip
- stream control. Id. at 1471. The final standard of 1,400 lb CO 2 /MWh
- g, adopted as a means of assuring reasonableness of costs, allows IGCC units to comply without using partial CCS. Thus, although the standard***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **184** of **763** can be met by a highly efficient new IGCC unit using app roximately 3 percent partial CCS (see section s V. E and V. H. 7 below), the EPA does not believe that implementation of partial CCS at such a low level, while technically feasible, is the option that utilities and project developers will choose. The EPA believes that IGCC project developers will either choose to meet the final standard by co
- firing with natural gas
- which would be a less costly and very straightforward process 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 co
-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

– meet the final standard by co - firing approximately 40 percent natural 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 part of the BSER for new steam generating EGUs, we remain convinced that it is t echnically feasible (see s ection V.E below) and believe that it represents a viable alternative compliance option that some project developers will consider to meet the final standard issued in this action. The EPA notes further that IGCC is available at reasonable cost (see Table 9 below), and involves***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **185** of **763** use of an advanced technology. So, although the final standard reflects performance of a BSER which includes partial CCS, even in the instances that a compliance alternative might be utilized , that alternat ive would both result in emission reductions consistent with use of the BSER, and would 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 heal th or the environment, 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 was not “currently considering” a standard of performance as high as 1,4 00 lb CO 2 /MWh
- g. 79 FR at 1471. However, in that same discussion , the EPA noted the reasons for its reservations (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 solicited comment on the issue: “We request that commenters who suggest emission rates above 1,200 lb CO 2 /MWh address potential concerns about providing adequate reductions and technology devel opment to be considered BSER.” Id. The proposal thus both solicited comment on higher emission standards (including 1 , 400 lb CO 2 /MWh
- g based***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **186** of **763** on a less aggressive rate of partial CCS ) , and provided ample notice of the methodology the EPA would use to determine the final BSER and the corresponding final standard . 181 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 the final standard is a logical outgrowth of the proposed rule. Allina Health Services v. Sebel ius , 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 also considered is provided in S ection V .P of this preamble . 182

181 Although co - firing with natural gas is not part of BSER, as noted above, it could be part of a compliance pathway for either SCPC or IGCC units. In this regard, a number of commenters addressed the issue of natural gas co
- firing, indicating that there were circumstances where it could be part of BSER. See e.g. Comments of Exel on Corp . p. 12 ; Comments of the Sierra Club p. [ ] . 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 comments). 182 Certain commenters maintained that the BSER determination does not comply with (purportedly) binding legal requirements created by regulations implementing the Information Quality Act. These comments are mistaken as a matter of both law and fact. The In formation Quality Act does not create legal rights 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 indicate s , 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **187** of **763** 2. BSER for Modified S team Generating Unit s The EPA has determined that, as proposed, the BSER for steam generating units that trigger the modification provisions is the modified unit’s own best potential performance. However,
as explained below, the final BSER determination and 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 potential performance would be det ermined depending upon when the unit implemented the modification ( i.e., before or after being subject to an approved CAA section 111(d) state plan). For units that commenced modification prior to becoming subject to an approved CAA section 111(d) state pl an, the EPA proposed unit
specific standards consistent with each modified unit’s best
one - year historical performance (during the years from 2002 to the time of the modification) plus an additional two percent reduction. For sources that commenced modific ation after becoming subject to an approved CAA section 111(d) plan, the EPA be implemented differently by different agencies accounting for circumstances). There are also significant factual omissions and mischaracterizations in these comments regarding peer review of the proposed standard and underlying record information. The complete response to these comments is in chapter 2 of the RTC. See also section V.I. 2.a and N below describing findings of the SAB panel that materials of the National Energy Technology Laboratory had been fully and adequately peer reviewed, and that EPA findings related to sequestration of captured CO 2 reflected the best available science.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **188** of **763** 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 upon when the modification commences , as long as it commences after June 18, 2014. We are establishing emission standards for large modifications in this rule and deferring at this time the setting of standards for small modifications. In this final action, the EPA is issuing final emission standards for affected steam generating units that implement large r modifications that are consistent with the proposed BSER determination for those units. The final standard for those
sources that implement large r modifications is a unit
- specific emission limitation consistent with each modified unit’s best
one - year historical performance (during the years from 2002 to the time of the modification ) , but does not include the additional two pe rcent reduction that was proposed in the January 2014 proposal. In this action, the EPA is not finalizing standards for those sources that conduct small er modifications and is withdrawing the proposed standards for those sources. See section XV below. A more detailed discussion of the rationale for the BSER determination and final standards is provided in Section VI of this preamble.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **189** of **763** 3. BSER for Reconstructed Steam Generating Units Consistent with our proposal, the EPA has determined that the BSER for rec onstructed steam generating units is the most efficient demonstrated generating technology for these types of units (i.e., meeting a standard of performance consistent with a reconstructed boiler using most the efficient steam conditions available, even if the boiler was not originally designed to do
so ). A more detailed discussion of the rationale for the BSER determination and the final standards is provided in S ection VII of this preamble . C. Final Standards of Performance The EPA is issuing final standards of performance for newly constructed, modified, and reconstructed affected steam generating units based on the degree of emission reduction achievable by application of the best system of emission reduction for those cate gories, as described above. The final standards are presented below in Table 6 . **Table 6**  **. Final Standards of Performance for New, Modified, and**  **Reconstructed Steam Generating Units Source**  **Description Final Standard** * **lb CO** **2 /** **MWh -** **g** New Sources All newly constructed steam generating EGUs 1,400

Modified Sources Sources that implement large r modifications

– Best annual performance (lb CO 2 /MWh - g ) during***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **190** of **763** those result ing in an increase in hourly CO 2 emissions (lb CO 2 /hr) of more than 10 percent 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 capacity of ≤ 2,000 mmBtu/hr. For newly constructed and reconstructed steam generating units and for modified steam generating sources that result in larger hourly increases of CO 2 emissions, the EPA is finalizing standards in the form of a gross energy output
-based CO 2 emission limit expressed in units of mass per useful energy output , specifically, in pounds of CO 2 per megawatt -hour (lb CO 2 /MWh g ). 183 The standard of performance will apply to affected EGUs upon the effective date of the final action. Compliance with the final standard will be demonstrated by
summing the emissions (in pounds of CO 2 ) for all operating hours in the 12
- operating
-month compliance period and then dividing

183 Note that the standards for sources that conduct larger 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 CO 2 emission limit expressed in pounds of CO 2 per megawatt -hour (lb CO 2 /MWh - g ) .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **191** of **7 63**  that value by the sum of the useful energy output (on a gross basis , i.e., gross megawatt
-hours ) over the rolling 12
- operating
-month compliance period. The final rule requires rounding of emission rates with numerical values greater than or equal to 1,000 to three significant figures and rounding of rates with numerical values less than 1,000 to two significant figures. For newly constructed steam generating units, we proposed two options for the compliance period. We proposed that a newly constructed source could choose to comply with a 12
- operating
month standard or with a more stringent standard over an 84
- operating
-month compliance period , and we solicited comment on including an interim 12
- operating
-month standard (based on use of supercritical boiler technology, see 79 FR at 1448). We are not finalizing the proposed 84
- operating
-month compliance period option because the final standard of performance for newly constructed sources is less stringent than the proposed standard and because, as discussed in S ection V below, we are identifying alternative compliance pathways for new steam generating EGUs . Specifically, we have concluded that there are unlikely to be significant issues with short
- term variability during initial operation, in view of both the reduced numerical stringency of the standard, and the availability of compliance alternatives . The EPA notes that co - firing of natural gas can also serve as an***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **192** of **763** interim means to reduce emissions if a new source operator believes additional time is needed to phase
- in the operation of a CCS system. Therefore, the applicable final standards of performance for all newly constructed, modified, and reconstructed steam generating units must be met over a rolling 12
- operating
-month compliance period. In the Clean Power Plan, which is a separate rulemaking under CAA section 111(d) published at the same time as the present rulemaking under CAA section 111(b) , the EPA is promulgating emission guidelines for states to develop state plans regulating CO 2 emissi ons from existing fossil fuel
- fired EGUs. Existing sources that are subject to state plans under CAA section 111(d) may undertake modifications or reconstructions and thereby become subject to the requirements under section 111(b) in the present rulemaking . In the section 111(d) Clean Power Plan rulemaking, the EPA discusses how undertaking a modification or reconstruction affects an existing source’s section 111(d) requirements. **V. Rationale for Final Standards for Newly Constructed Fossil Fuel**  **- fired Elec** **tric Utility Steam Generating Units** In the discussion below, the EPA describes the rationale and justification of the BSER determination and the resulting final standards of performance for newly constructed steam***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **193** of **763** generating units. We also explain why this determination is consistent with the constraints imposed by the EPAct05. A. Factors Considered in Determining the BSER In evaluating the final determination of the BSER for newly constructed steam generating units, the EPA considered the factors for the BSER described above, looked widely at all relevant information and considered all the data, information, 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 constructe d fossil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of new coal
- fired generating sources that addresses GHG emissions . B. Highly Efficient SCPC EGU Implementing Partial CCS a s the BSER for Newly Constructed Steam Generating Units In the sections that follow, we explain the technical configurations that may be used to implement BSER to meet the final standard, describe the operational flexibilities that partial CCS offers, and then provide the rationale for the final standard of performance. After that, we discuss, in greater***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **194** of **763** detail, consideration of the criteria for the determination of the BSER . We describe why a highly efficient new SCPC 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 system is technically feasible, provides meaningful emission reductions, can be implemented at a reasonable cost , does not pose non - air quality health and environmental concerns or impair energy reliability, and consequently is adequately demonstrated . We also explain why the emission standard of 1,400 lb CO 2 /MWh
- g is achievable, including under all circumstances reasonably likely to occur when the system is properly designed and operated. We also discuss alternative compliance options that new source project developers can elect to use , instead of SCPC with partial CCS, to meet the final standard of performance. C. Rationale for the Final Emission Standards 1. The Proposed Standards In the January 2014 proposal, the EPA proposed an emission limitation of 1,100 lb CO 2 /MWh - g , which a new highly efficient utility boiler burning bituminous coal could have met by capturing roughly 40 percent of its CO 2 emissions and a new highly efficient IGCC unit could have me t by capturing and storing roughly 25 percent of its CO 2 emissions . The captured CO 2 would then be securely stored in sequestration repositories***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **195** of **763** subject to either Class II or Class VI standards under the Underground Injection Control program. The EPA arrived at the proposed standard by examining the available CCS implementation configurat ions and concluding that the proposed standard at the corresponding level s of partial CCS best balanced the BSER criteria and resulted in an achievable emission level . The EPA also propose d to find that highly efficient new generation 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 units
- are projected to substantially exceed the projected costs of other
non -NGCC dispatchable technologies that utilities and project developers are considering (e.g., new nuclear and biomass). See generally 79 FR at 1477
- 78. Conversely, the EPA rejected highly eff icient SCPC as the BSER because it would not result in meaningful emission reductions from any newly constructed PC unit. Id. at 1470. The EPA also declined to base the 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 F inal S tandards For this final action, the EPA reexamined the BSER options available at proposal. Those options are: (1) highly efficient generation without CCS, (2) highly efficient generation implementing partial CCS, and (3) highly efficient generation***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **196** of **763** implementing full CCS . Consistent with our determination in the January 2014 proposal, we remain convinced that highly efficient generation (i.e., a new supercritical utility boiler or a new IGCC unit) without CCS does not represent the BSER because it does not achieve emission reductions beyond the sector’s business as usual , when options that do achieve more emission reductions are available . 79 FR 1470 ; see also section V.P below . We also do not find that a highly efficient new steam generating unit implementing full CCS is the BSER because, at this time, the costs are predicted to be significantly more than the costs for implementation of partial CCS and significantly more than the costs for competing non -NGCC base load, dispatchable technologies
- primarily new nuclear generation
- and are , therefore, potentially unreasonable . See section V.P. As with the proposal , the EPA has determined the final BSER and corresponding emission limitation by appropriately 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 reflect s changes that are responsive to comments received on , and the EPA’s further evaluation of, the costs to implement partial CCS. The EPA has determined that a newly constructed highly efficient supercritical utility boiler burni ng bituminous coal can meet this final emission limitation by capturing 16 percent of the CO 2***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **197** of **763** produced from the facility (or 23 percent if burning subbituminous or dried lignite) , which would be either stored in
on - site or off
- site geologic sequestration repositories subject to control under either the Class VI (for geologic sequestration) or Class II (for Enhanced Oil Recovery) standards under the UIC program . Th is BSER is technically feasible , as shown by the fact that post - combustion CCS technology

– both the capture and storage components - is demonstrated in full
- scale operation within the electricity generating industry . There are also numerous operating results from smaller
- scale projects that are reasonably predictive of operation at full
- scale. It is available at reasonable cost, does not have collateral adverse
non - air quality health or environmental impacts, and does not have adverse energy implications. The proposed BSER was a h ighly efficient newly constructed 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 achieve an emission standard of 1,400 lb CO 2 /MWh
- g. In both cases , the EPA specified that the BSER includes a “highly efficient” new EGU implementing partial CCS. This assumes that a new project developer will construct the most efficient generating technology available

– i.e., a supercritical or ultra
supercr itical utility boiler

– that will inherently generate***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **198** of **763** 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 meet the final standa rd of 1,400 lb CO 2 /MWh
- g than a less efficient new steam generating EGU. The construction of highly efficient steam generating EGUs

– as opposed to less efficient units such as a subcritical utility boiler

– will result in lower overall costs from decrease d fuel consumption and the need for lower levels of required partial CCS to meet the final standard . 3. Consideration of P rojec ts Receiving Funding Under the EPAct05 As noted in section III.H.3.g above, the EPA’s determination of the BSER here includes review of recently constructed facilities and those planned or under construction to evaluate the control technologies being used and considered. Some of the projects discussed in the January 2014 proposal, and discussed here in this preamble, received or are receiving financial assistance under the EPAct05 (P.L. 109
- 58). This assistance may include financial assistance from the Department of Energy (DOE) , as well as receipt of the Federal tax credit for investment in clean coal technolo gy under IRC section 48A. As noted above, the EPA interprets these provisions as allowing consideration of EPAct05 facilities provided that such information is not the sole basis for the BSER determination, and particularly so in circumstances like those here, where the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **199** of **763** information is corroborative but the essential information justifying the determinations comes from facilities and other sources of information with no nexus with EPAct05 assistance. I n the discussion below, the EPA explains its reliance on other information in making the BSER determination for new fossil fuel - fired steam generating units. The EPA notes that information from facilities that did not receive any DOE assistance , and did not receive the Federal tax credit, is sufficient by itself to support its BSER determination. D. Post - Combustion Carbon Capture In this section , we describe a variety of facts that support our conclusion that the technical feasibility of post combustion carbon capture is adequately demonstrated. First, we 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 explain and justi fy our conclusions that the technical feasibility of other aspects of partial CCS are adequately demonstrated

– namely, the transportation and carbon storage ( see s ec tions V. M . and N ). Further , the conclusions of this section are reinforced by the discussion in section V.F. below , in which we identify commercial vendors that offer carbon capture technology and offer performance guarantees , and discuss i ndustry and***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **200** of **763** technology developers ’ public pronouncements of their confidence in the feasibility and availability of CCS technologies. 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 utility boiler. It is referred to as “post
- combustion capture” because the CO 2 is the product of the combustion of the primary fuel and the capture takes place after the combustion of that fuel. 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 somewhat dilute. 184 Most post - combustion capture systems utilize liqui d solvents 185 that separate the CO 2 from the flue gas in CO 2 scrubber systems . Because the flue gas is at atmospheric pressure and is somewhat dilute, the solvents used for post
combustion capture are ones that separate the CO 2 using chemical absorption (or chemisorption). Amine
-based solvents 186 are the most commonly used in post
- combustion capture systems. In a chemisorption
-based separation process, the flue gas is

184 The typical concentration of CO 2 in the flue gas of a coal
fired utility boiler is roughly around 15 volume percent. 185 A solvent is a substance (usually a liquid) that dissolves a solute (a chemically different liquid, solid or gas), resulting in a solution. 186 Amines are derivatives of ammonia (NH 3 ) where one or more hydrogen atoms have been replaced by hydrocarbon groups.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **201** of **763** 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 “solvent regeneration” and is responsible for much of the “energy penalty” of the capture system. Steam from the boiler (or potentially from another external source) that would otherwise be used to generate electricity is instead used in the solvent regeneration process. The development of advanced solvents

– those that are chemically stable, have high CO 2 absorption capacities, and have low regeneration energy requirements

– is an active area of research. Many post
- combustion solvents will 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 acidic gases will need to be scrubbed to very low levels prior to the flue gas entering the CO 2 capture system. See also RIA chapter 5 (quantifying SO 2 reductions resulting from this scrubbing process).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **202** of **763** Additional information on post
- combustion carbon capture

– including process diagrams
- can be found in a summary technical support document. 187 2. Post - Combustion Carbon Capture Projects that Have Not Received DOE Assistance Through the EPAct05 or Tax Credits Under IRC S ection 48A
a. Boundary Dam Unit #3 . SaskPower’s Boundary Dam CCS Project in Estevan, a city in Saskatchewan, Canada, is the world’s first commercial
- scale fully integrated post
- combustion CCS project at a coal - fired power plant. The project fully integrates the rebuilt 110 MW coal
- fired Unit #3 with a CO 2 capture system using Shell Cansolv amine
-based solvent to capture 90 percent of its CO 2 emissions. The facility, which utilizes local Saskatchewan lignite, began operations in October 2014 and accounts of the system’s performance describe it as working even “better than expected.” 188 , 189 The plant started by capturing roughly 75 percent

187 Technical Support Document

– “Literature Survey of Carbon Capture Technology”, available in the rulemaking docket (Docket ID: EPA- HQ - OAR- 2013
- 0495). 188 “[W]e are achieving better than expected” operation out of the plant, SaskPower's Mike Marsh said April 8, 2015 in Washington, DC, summarizing the status of the first
- of - a - kind plant in Saskatchewan, Canada, known as Boundary Dam Unit 3. Marsh spoke at a meeting of the National Coal Council, which advises the Energy Department on coal
- re lated topics. From “Bolstering EPA’s NSPS, Canadian CCS Plant Working ‘Better Than Expected’”, Climate Daily News, Inside EPA/climate (Apr il 08, 2015); www.insideepa.com (subscription required).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **203** of **763** of CO 2 from the plant emissions and its operators plan to increase the capture percentage as they optimize the equipment to reach full capacity. Initial indications are that 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 . 190 Water use at the facility is consistent with levels that were predicted. 191 The total project costs

– for the power plant and the carbon capture plant

– was $1.467B (CAD). 192 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. 193 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
189 “CCS performance data exceeding expectations at world
- first Boundary Dam Power Station Unit #3”, http://www.saskpowerccs.com/newsandmedia /latest
- news/ccs
performance - data - exceeding
- expectations/ 190 Correspondence between Mike Monea (SaskPower) and Nick Hutson (EPA), February 20, 2015. 191 30 percent of the water used for cooling comes from the recycled or reclaimed water from the process itsel f ; namely , water in the coal is reclaimed. 192 About $1.2B USD ; roughly $700M (USD) for the carbon capture system, which was on budget. 193 “Boundary Dam

– The Future is Here”, plenary presentation by Mike Monea at the 12 th International Conference on Greenhouse Gas Technologies (GHGT
- 12), Austin, TX (October 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **204** of **763** 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 electricity production of the plant. Some commenters noted that, at 110 MW, the Boundary Dam Unit #3 is a relatively small coal - fired utility boiler and thus , in the commenters ’ view, does not demonstrate that such a system could be utilized at a much larger utility coal
- fired boiler. However, there is nothing to indicate that the post
combustion system used at Boundary Dam could not be scaled- up for use at a larger utility boiler . In fact, the carbon capture system at Boundary Dam #3 is designed and constructed to implement “full CCS”

– that is to capture more than 90 percent of the CO 2 produced from the subcritical unit. A similarly
- sized capture system
– with no need for further scale
- up - could be used to treat a slip
- stream of a much larger supercritical utility boiler ( a new unit of approximately 500 to 600 MW) in order to meet the final standard of 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 coal 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 coal
- fired***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **205** of **763** boiler to be separated into two or more streams and treated separately in different control equipment before being recombined to exit from a common stack. 194 A slip
- stream configuration is often used to treat a smaller portion of the bulk flue gas stream as a way of testing or demonstrating a control device or measurement technology. For implementation of post - combustion partial carbon capture, a portion of the bulk flue gas stream would be treated separately to capture approximately 90 percent of the CO 2 from that smaller slip
- stream of the flue gas. For example, in order to capture 20 percent of the CO 2 produced by a coal - fired utility boiler, an operator would treat approximately 25 percent of the bulk flue gas stream (rather than treating the entire stream). Approximately 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 slip
stream approach was the most economical for carbon capture of less than 90 percent of the total CO 2 . 195 The advantage of the

194 See Figure 1A from Atmospheric Environment , 43, 3974 (2009), for an example of this type of configuration. 195 “Cost and Performance of PC and IGCC for a Range of 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) approach. Indeed, the slip
- stream approach is more cost
- effective for <90***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **206** of **763** slip
- stream approach is that the capture system will be sized to treat a lower volume of flue gas flow , which reduces the size of the CO 2 absorption columns, induced draft fans, and other equipment , leading to lower capital and operating costs. The carbon capture system at Boundary Dam does not utilize the slip
- stream configuration because it was designed to achieve more than 90 percent capture rates from the 110 MW facility. 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 plant can be utilized for parti al carbon capture at a much larger coal - fired unit without the need for further scale
- up. The experience at Boundary Dam is directly transferrable to other types of post - combustion sources , including those using different boiler types and those burning dif ferent coal type s. There is nothing to suggest that the Shell CanSolv process would not work with other coal types and indeed, the latest NETL cost estimates assume that the capture technology would be used in a 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 (documenting further that treat ing a slip
- stream is the most economical approach).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **207** of **763** new unit using bituminous coal. 196 The EPA is unaware of any reasons why the Boundary Dam technology would not be transferrable to another utility boiler at a different location at a different elevation or climate because the control technology is not climate or elevation
- dependent . Commenters a lso noted that the Boundary Dam Unit #3 project received financial assistance from both the Canadian federal government and from the Saskatchewan provincial government. But the availability of

– or the lack of

– external financial assistance does not affec t the technical feasibility of the technology. Commenters further characterized Boundary Dam as a “demonstration project”. These descriptors are beside the point. Regardless of what the project is called or how it was financed , the project clearly shows the technical feasibility of full
scale, fully integrated implementation of available post combustion CCS technology , which in this case also appears to be commercially viable .

196 In fact, in “Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coa l (PC) and Natural Gas to Electricity Revision 3”, DOE/NETL
- 2015/1723 (July 2015 ), Exh.2
- 3 the Shell Cansolv process is used as the capture process 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 used effectively for bituminous coa l since this type of coal is assumed for cost estimation purposes.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **208** of **763** The EPA notes that, although there is ample additional information corroborating that post
- combustion CCS is technically feasible, which we describe below , the performance at Boundary Dam Unit #3 alone would be sufficient to support that conclusion. Essex Chemical Corp., 486 F. 2d at 436 (test results from single facility demonstrates achievability of standard of performance). As mentioned above, the post
combustion 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 Shady Point (Panama, OK) are both circulating fluidized bed (CFB) coal
- fired power plants with carbon capture amine scrubbers developed by ABB/Lummus. The scrubbers were designed to process a slip
- stream of each plant’s flue gas. At the 180 MW Warrior Run plant, a plant that burns bituminous coal, approximately 10 percent of the plant’s CO 2 emissions (about 110,000 metric tons of CO 2 per year) has been captured since 2000 and sold to the food and beverage industry. At the 320 MW Shady Point Plant, a plant that burns a blend of bituminous and subbituminous coals, CO 2 from an approximate 5 percent slip
- stream (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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **209** of **763** industry. 197 While these projects do not demonstrate the CO 2 storage component of CCS, they clearly demonstrate the technical viability of partial CO 2 capture. The capture of CO 2 from a slip
stream of the bulk flue gas, as described earlier, is the most economical method for capturing less than 90 percent of the CO 2 . The amounts of partial capture that these sources have demonstrated

– 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 standard of performance. These facilities, which have been operating for multiple years, clearly show the technical feasibility of post
- combustion carbon capture.
c. Searles Valley Minerals . Since 1978, the Searles Valley Minerals soda ash plant 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 steam and power for on - site use. The captured CO 2 is used for the carbonation of brine in the process of producing soda ash. 198 Again, while the captured CO 2 is not sequestered , this project clearly demonstrates the technical feasibility of

197 Do oley, J. J., et al. (2009). “An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009 ” . U.S. DOE, Pacific Northwest National Laboratory, under Contract DE -AC05
- 76RL01830. 198 IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **210** of **763** the amine scrubbing system for CO 2 capture from a coal - fired power plant. 199 The fact that this system is an industrial coal
fired power plant rather than a utility coal
- fired power plant is irre levant as they both serve a similar purpose

– the production of electricity. Each of these processes indicate a willingness of industry to utilize available post
- combustion technology for capture of CO 2 for commercial purposes. Not one of the CO 2 capture s ystems at Warrior Run, Shady Point, or Searles Valley was installed for regulatory purposes or as government - funded demonstration 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 efficient, and

199 Moreover, the final rule allows alternative me ans of storage of captured CO 2 based on a case -by- case demonstration of efficacy. See section V.M.3 below.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **211** of **763** the amine scrubbi ng system to be used at the Petra Nova WA Parish project ( Thompsons, TX) is projected to be as well . 200 3. Post - Combustion Carbon Capture Projects that Received DOE Assistance through the EPAct05 , but Did Not Receive Tax Credits under IRC S ection 48A The EPA considers the experiences from the CCS projects described above, coupled with facts that the design of CCS is well accepted (also described above) and the strong support that CCS has received from vendors and others (described below) to adequately demonstrate that post - combustion partial CCS is technically feasible . The EPA finds that additional projects, described next, provide more support for that conclusion . These projects received funding under EPAct05 from the Department of Energy, but that does not disqualify them from being considered. See S ection III.H.3 above.
a. Petra Nova WA Parish Project . Petra Nova, a joint venture between NRG and JX Nippon Oil & Gas Exploration, is constructing a commercial
- scale post - combustion carbon capture project at Unit #8 of NRG's WA Parish generating station southwest of
200 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 Scrubbing 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 (October 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **212** of **763** Houston, Texas. The project is designed to utilize partial CCS by capturing approximately 90 pe rcent of the CO 2 from a 240 MW slip
- stream of the 610 MW WA Parish facility. The project is expected 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 technical feasibility of the post - combustion carbon c apture system . The project was originally envisioned as a 60 MW slip
stream demonstration and received DOE Clean Coal Power Initiative ( CCPI ) funding (as provided in EPAct05) on that basis. The developers later expanded the project to the larger 240 MW slip
- stream because of the need to capture greater 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 . 201 At 240 MW, the Petra Nova project will be the largest post combustion carbon capture system installed on an existing coal
fueled power plant. The project will use for EOR or will

201 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 project. In any case, as described above, even without consideration of this facility at all, other information adequately demonstrates the technical feasibility of post
- combustion CCS.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **213** of **763** sequester 1.6 million tons of captured CO 2 each year. The project is expected to be operational in 2016. In 2014 project materials , 202 the project developer NRG recognized the importance of CCS technology by noting: The technology has the potential to enhance the longterm viability and sustainability of coal - fueled power plants across the U.S. and around the world.
... Post combustion carbon capture is essential so that we can use coal to sustain our energy ecosystem while we begin reducing our carbon footprint . According to NRG, the Petra Nova Carbon Capture Project will utilize “a proven carbon capture process ,” j ointly developed by Mitsubishi Heavy Industries, Ltd. (MHI) and the Kansai Electric Power Co., that uses a high
-performance solvent for CO 2 absorption and desorption. 203 In using the MHI high
performance solvent, the Petra Nova project will benefit from pilo t - scale testing of this solvent at Alabama Power’s Plant Barry and at other installations. WA Parish Unit #8 came on
- line in 1982 and is thus an existing source that will not be subject to final standards of performance issued in this action. However, because it will be capturing roughly 35 percent of the

202 WA Parish CO 2 Capture Project Fact Sheet; available at www.nrg.com/documents/business/pla
- 2014
-petranova -waparish
factsheet.pdf (2014) 203 The WA Parish project (described earlier) will utilize the KM- CDR Process®, which was jointly developed by MHI and the Kansai Electric Power Co., Inc. and uses the proprietary KS
- 1TM high
-performance solvent for the CO 2 absorption and desorption.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **214** of **763** CO 2 generated by the facility, it s emissions will be below the final new source emission limitation of 1,400 lb CO 2 /MWh - g . 204 The captured CO 2 from the WA Parish CO 2 Capture Project will be used in EOR operations at mature oil fields in the Gulf Coast region. Using EOR at Hilcorp's West Ranch Oil Field, the production is expected to be boosted from around 500 barrels per day to approximately 15,000 barrels per day. Thus the 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 for EOR and eventual geologic storage. The carbon capture system at WA Parish will utilize a slip
stream 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
- stream from a 1,000 MW unit in order to meet the final standard of performance of 1,400 lb CO 2 /MWh - g . Again, the experience at the WA Parish Unit #8 project will be directly transferable to post
- combustion capture at a new
204 Using emissions data reported to the Acid Rain Program, 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
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– Do Not Cite, Quote or Release During Review *** Page **215** of **763** 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 transferrable to other types of post - combustion sources including those using different boiler types and those burning different coals. The amine scrubbing and associated systems are not boiler type
- or coal - specific. The EPA is unaware of any reasons that the technology utilized at the WA Parish plant would not be transferrable to another utility boiler at a different location at a different elevation or climate , given that the technology is not dependent on either climate or topography . b. AEP/Alstom Mountaineer 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 - fired unit that was retrofitted with Alstom’s patented chilled ammonia CO 2 capture technology on a 20 MWe slip
- stream of the plant’s exhaust flue gas. In May 2011, Alstom Power announced the successful operation of the chilled ammonia CCS validation project. The demonstration achieved capture rates from 75 percent (design value) to as high as 90 percent, and produced CO 2 at a purity of greater than 99 percent, with energy penalties within a few percent of predictions. The facility***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **216** of **763** reported robust steady- state operation during all modes of power plant operation , including load changes, and saw an avail ability of the CCS system of greater than 90 percent. 205 AEP, with assistance from the DOE, had planned to expand the slip
- stream demonstration to a commercial scale, fully integrated demonstration at the Mountaineer facility. 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 proj ect to be completed in four phases, with the system to begin commercial operation in 2015. However, in July 2011, AEP announced that it would terminate its cooperative agreement with the DOE and place its plans to advance CO 2 capture and storage technology to commercial scale on hold . AEP cit ed the uncertain status of U.S. climate policy as a contributor to its decision , but did not express doubts about the feasibility of the technology . See S ection V.L below. AEP also prepared a Front End Engineering & Design (FEED) Report , 206 explaining in detail how its pilot
- scale work could be scaled up to successful full - scale operation, and to accommodate
205 http://www.alstom.com/press
- centre/2011/5/alstom
- announces sucessful - results - of -mountaineer
- carbon - capture - andsequestration
- ccs -project/ 206 “ CCS front end engineering & design report: American Electric Power Mountaineer CCS II Project. Phase 1”, pp 10
- 11; ava ilable at: http://www.globalccsinstitute.com/publications/aep
mountaineer
- ii
-project
- front - end- engineering
- and- design
- feedreport***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **217** of **763** the operating needs of a full
- scale EGU, including reliable generating capacity capable of cycling up and down to accommodate consumer demand. Recommended design changes to accomplish the desired scaling included detailed flue gas specifications, ranges for temperature, moisture and SO 2 content; careful scrutiny of makeup water composition and temperature; quality and quantity of available steam to accommodate heat cycle based on unit load changes; and detailed scrutiny of material and energy balances. 207 See S ection V.G.3 below, addressing in more detail the record support for how CCS technology can be scaled up to commercial size in both 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 coal
- fired carbon capture facility at Alabama Power’s Plant Barry. 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 employed the KM CDR Process, which uses a
207 Id. at 11. The EPA does not view this information as being affected by the constraints in EPAct05. The information does not relate to use of technology, level of emission reduction by reason of use of technology, achievement of emission reduction by demonstration of technology, or demonstration of a level of performance. The FEED study rather explains engineering challenges which would remain at full scale and how those challenges can be addressed.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **218** of **763** proprietary high performing solvent 208 for CO 2 absorption and desorption that was jointly developed 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. 209 Project participants have reported that “[t]he plant performance was stable at the full load condition with CO 2 capture rate of 500 TPD at 90 percent CO 2 removal and lower steam consumption than conventional capture processes.” 210 E. Pre - Combustion Carbon Capture As described earlier, the EPA does not find that IGCC technology

– either alone or implementing partial CCS

– is part of the BSER for newly constructed steam generating EGUs. However, as noted, there may be specific circums tances 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 justify our conclusion that the technical feasibility of pre
- combustion
208 This is the same carbon capture system that is being utilized at the Petra Nova project at the NRG WA Parish plant. 209 Ivie, M.A. et al.; “Project Status and Research Plans of 500 TPD CO2 Capture and Sequestration Demonstration at Alabama Power’s Plant Barry”, Energy Procedia 37, 6335 (2013 ). 210 Id.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **219** of **763** carbon capture is adequately demonstrated , indicating that this could be a viable alternative compliance pathway . First, we explain the technology of pre
- combustion capture. We then describe EGUs that have previously utilized or are currently utilizing pre
- combustion carbon capture technology. This discussion is complemented by other sections that conclude the technical feasibility of other aspects of partial CCS are adequately demonstrated

– namel y, post - combustion carbon capture ( Sec tion V.D ) and sequestration ( Sections V. M and V. N ). Further, this section’s conclusions are reinforced by Section V.F , in which we identify commercial vendors that offer CCS performance guarantees as well as developers that have publicly stated their confidence in CCS technologies. 1. Pre
- Combustion Carbon Capture

– How it Works Pre - combustion capture systems are typically used with IGCC processes. In a gasification system, the fuel (usually coal or petroleum coke) is heated with water and oxygen in an oxygen
lean environment. The coal (carbon), water and oxygen 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 2O + O 2  H 2 + 3CO In an IGCC system, the resulting syngas, after removal of the impurities, can be combusted using a conventional combu stion***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **220** of **763** turbine in a combined cycle configuration (i.e., a combustion turbine combined with a HRSG and steam turbine). The gasification process also typically produces some amount of CO 2 211 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 steam (“water”) with CO (“gas”) to form H 2 and CO 2 according to the following catalytic reaction: CO + H 2O  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 “shift” prior to treatment in the pre
- combustion acid gas treatment system. If a high level of CO 2 capture is required, then multi
- stage WGS reactors will be needed and an advanced hydrogen turbine 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

211 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/gasification/gas ifipedia/4
- gasifiers/4
- 3_syngastable2.html).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **221** of **763**
concentration). As such, the pre
- combustion capture systems can utilize physical absorption (physisorption) solvents rather than the chemical absorptions solvents described earlier. Physical absorption has the benefit of rel ying on weak intermolecular interact ions and, as a result, the absorbed CO 2 can often be released (desorbed) by reducing the pressure rather than by adding heat. Pre
- combustion capture systems have been used widely in industrial processes such as natural gas processing. Additional information on pre - combustion carbon capture can be found in a summary technical support document. 212 2. Pre - Combustion Carbon Capture Projects that Have Not Received DOE Assistance Through EPAct05 or Tax Credits Under IRC S ection 48A
a. Dakota Gasification Great Plains Synfuels Plant . Each day , the Dakota Gasification Great Plains Synfuels Plant uses approximately 18,000 tons of North Dakota lignite in a coal gasification process that produces syngas (a mixture of carbon
monox ide, carbon dioxide, and hydrogen ) , which is then converted to methane gas (synthetic natural gas) using a methanation process. Each day , the process produces an average of 145 million cubic feet of synthetic natural gas that is ultimately

212 Te chnical Support Document
– “Literature Survey of Carbon Capture Technology”, available in the rulemaking docket (Docket ID: EPA- HQ - OAR- 2013
- 0495).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **222** of **763** transported for use in home heating and electricity generation. 213 Capture of CO 2 from the facility began in 2000. The Synfuels Plant, using a pre
- combustion Rectisol® process, captures about 3 million tons of CO 2 per year - more CO 2 from coal conversion than any facility in the world, and is a participant in the world's largest carbon sequestration project. On average about 8,000 metric tons per day of captured CO 2 from the facility is sent through a 205
-mile pipeline to oil fields i n Saskatchewan, Canada, where it is used for EOR operations that result in permanent CO 2 geologic storage. The geologic sequestration of CO 2 in the oil reservoir is monitored by the International Energy Agency (IEA) Weyburn CO 2 Monitoring and Storage Proje ct. Several commenters to the January 2014 proposal argued that the Great Plains Synfuels facility is not an EGU, that it operates as a chemical plant, and that its experience is not translatable to an IGCC using pre
- combustion carbon capture technology. The commenters noted that the Dakota facility can be operat ed nearly continuously without the need to adjust operations to meet cyclic electricity generation demands. In the January 2014 proposal , the EPA had noted that , while the facility is not an EGU, it has significant similarities to an

213 http://www.dakotagas.com/Gasification/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **223** of **763** IGCC and the imp lementation of the pre
- combustion capture technology would be similar enough for comparison. See 79 FR at 1435
- 36 and n. 11. We continue to hold this view. As explained above, in an IGCC gasification system, coal (or petroleum coke) is gasified to produce a synthesis 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 using water ( H 2O, steam) is then used to shift the syngas to CO 2 and H 2 . The more the syngas is “shifted , ” the more enriched it becomes in H 2 . In an IGCC , power can be generated by directly combusting the
un - shifted syngas in a conventional combustion turbine. If the syngas is shifted such that the resulting syngas is highly enriched in H 2 , then a special, advance d hydrogen turbine is needed. If CO 2 is to be captured, then the syngas would need to be shifted either fully or partially, depending upon the level of capture required. 214 The Dakota Gasification process bears essential similarities to the just
- described IGCC gasification system . As with the IGCC gasification system, the Dakota Gasification facility gasifies coal (lignite) to produce a syngas which is then shifted to increase the concentration of CO 2 and to produce
214 “Cost and Performance of PC and IGCC for a Range of Carbon Capture ”, Rev 1 ( 2013), DOE/NETL
- 2011/1498.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **224** of **763** 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 syngas is used distinguishes the IGCC gasification system from the Dakota Gasification facility. In the IGCC process, the syngas is combus ted. In the Dakota Gasification facility, the syngas is processed through a catalytic methanation process where the CO and H 2 react to produce CH 4 (methane, synthetic natural gas) and water. Importantly, the CO 2 capture system that is used in the Dakota Gasification facility can readily be used in an IGCC EGU. There is no indication that the RECTISOL® process (or other similar physical gas removal systems) is not feasible for an IGCC EGU. In confirmation, a ccording to product literature, RECTISOL®, which was independently developed by Linde and Lurgi, is frequent ly used to purify shifted, partially shifted or un
shifted gas from the gasification of coal, lignite, and residual oil. 215 b. International projects . There are some international projects that are in various stages of development that indicate confidence by developers in the technical feasibility of pre
-

215 www.linde
engineering.com/en/process_plants/hydrogen_and_synthesis_gas_pla nts/gas_processing/rectisol_wash/index.html***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **225** of **763** combustion carbon capture. Summit Carbon Capture, LLC is developing the Caledonia 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 and sub - sea pipeline for sequestration in a saline formation in the North Sea. The U.K. Department of Energy & Climate Change (DECC) recently announced funding to allow for feas ibility studies for this plant. 216 Commercial operation is expected in 2017. 217 The China Huaneng Group

– with multiple collaborators, including Peabody Energy, the world’s largest private sector coal company - is building the 400 MW GreenGen IGCC facility in Tianjin City, China. The goal is to complete the power 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. 218 Vattenfall and Nuon’s pilot project in Bugennum, The Netherlands involves carbon capture from coal - and biomass
- fired IGCC plants. It has operated since 2011. 219

216 http://www.downstreambusiness.c om/item/Summit
- Power -Wins
Funding
- Studies
- Proposed- IGCC - CCS - Projec t_140878 217 http://www.summitpower.com/projects/carbon
- capture/ 218 http://sequestration.mit.edu/tools/projects/greengen.html 219 Buggenum Fact Sheet: Carbon Dioxide Capture and Storage Project, Carbon Capture & Sequestration Technologies @ MIT,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **226** of **763** 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. 220 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 operations are scheduled to begin by 2016. 221 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 . 222 The experience of the Dakota Gasification facility, coupled with the descriptions of the technology in the literature, the statements from vendors, and the experience of facilities internationally, are sufficient to support our determination that the technical feasibility of CCS for an IGCC facility is adequately demonstrated. The experience of additional facilities, described next, provides additional support. http://sequestration.mit.edu/tools/projects/buggenum.html (last visited ). 220 Puertollano Fact Sheet: Carbon Dioxide Capture and Storage Project, Carbon Capture & Sequestration Technologies @ MIT, https://sequestration.mit.edu/tools/projects/puertoll anto.html (last visited ). 221 ESI CCS Project Fact Sheet: Carbon Dioxide and Storage Project, Carbon Capture & Sequestration Technologies @ MIT, http://sequestration.mit.edu/tools/projects/esi
- ccs -project . 222 Utmaniyah CO 2 EOR Demonstration Project, Globa l CCS Institute, http://www.globalccsinstitue.com/project/uthmaniyah
- co2
- eor demonstration
-project
- 0 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **227** of **763** 3 . Pre - Combustion Carbon Capture Projects that Have Received DOE Assistance Through EPAct05 , but Did Not Receive Tax C redits Under IRC S ection 48A
a. Coffeyville Fertilizer . Coffeyville Resources Nitrogen Fertilizers, LLC, owns and operates a nitrogen fertilizer facility in Coffeyville, Kansas. The plant began operation in 2000 and is the only one in North America using a petroleum coke -based fertilizer production process. The petroleum coke is generated at an oil refinery adjacent to the plant. The petroleum coke is gasified to produce a hydrogen rich synthetic gas, from which ammonia and urea ammonium nitrate fertilizers are subsequently synthesized. As a by
‐ product of manufacturing fertilizers, the plant also produces significant amounts of CO 2 . In March 2011, Chaparral Energy announced a long- term agreement for the purchase of captured CO 2 which is transported 68 miles via CO 2 pipeline for use in EOR operations in Osage C ounty, OK. Injection at the site started in 2013. At least one commenter suggested that the cost and complexity of carbon capture from these and other industrial projects was significantly decreased because the sources already separate CO 2 as part of their normal operations. The EPA finds this argument unconvincing. The Coffeyville process involves***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **228** of **763** gasification of a solid fossil fuel (pet coke), shifting the resulting syngas stream, and separation of the resulting CO 2 using a pre
- combustion carbon capture system. These are the same, or very similar, processes that are used in an IGCC EGU. The argument is even less convincing when considering that the Coffeyville Fertilizer process uses the SelexolTM pre
- combustion capture process
– the same p rocess that Mississippi Power described as having been “in commercial use in the chemical industry for decades” and is expected by Mississippi Power to “pose little technology risk” when used at the Kemper IGCC EGU. 4. Pre - Combustion Carbon Capture Projects that have Received DOE Assistance Through EPAct05 and Tax Credits Under IRC S ection 48A
a. Kemper County Energy Facility . Southern Company’s subsidiary Mississippi Power has constructed the Kemper County Energy Facility in Kemper County, MS. This is a 582 MW IGCC plant that will utilize local Mississippi lignite and includes a pre
combustion carbon 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 Service Commission for the Kemper project, Mississippi described the carbon capture system: The Kemper County IGCC Project will capture and compress approximately 65% of the Plant's CO 2 [...] a process referred to as SelexolTM is applied to remove***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **229** of **763** 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 have been in commercial use in the chemical industry for decades and pose little technology risk. (emphasis added) 223
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 technical risk when used in the Kemper IGCC EGU. b. Texas Clean Energy Project and Hydro gen Energy California Project. The Texas Clean Energy Project (TCEP) , a 400 MW IGCC facility located near Odessa, Texas will capture 90 percent of its CO 2 , which is approximately 3 million metric tons annually. The captured CO 2 will be used for EOR in the West Texas Permian Basin. Additionally, the plant will produce urea and smaller quantities of commercial
- grade sulfuric acid, argon, and inert slag, all of which will also be marketed. Summit has announced that they expect to commence construction on the p roject in 2015. 224 The facility will utilize the Linde Rectisol® gas cleanup process to capture carbon dioxide 225

– the same process

223 Mississippi Power Company, Kemper County IGCC Certific ate Filing, Updated Design, Description and Cos t of Kemper IGCC Project, Mis sissippi Public Service Commission (MPSC) DOCKET NO. 2009
-UA- 0014, filed December 7, 2009. 224 “Odessa coal - to - gas power plant to break ground this year”, Houston Chronicle (April 1, 2015). 225 http://www.texascleanenergyproject.com/project/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **230** of **763** that has been deployed for decades, including at the Dakota Gasification facility , a clear indication of the developer’s confidence in that technology and further evidence that the Dakota Gasification carbon capture technology is transferable 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 demonstrated to be technically feasible. This includes performance guarantees from vendors , public statements from industry officials , and review of the literature. 1. Performance Guarantees The D.C. Circuit made clear in its first cases concerning CAA section 111 standards, and has affirmed since then, that performance guarantees from vendors are an important basis for support ing a determination that pollution technology is adequately demonstrated to be technically feasible. In 1973, in Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 440 (D.C. Cir. 1973) , the Court upheld standards of performance for coal - fired steam generators based on “prototype testing data and full - scale control systems, considerations of available fuel supplies, literature sources, and documentation of manufacturer guarantees***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **231** of **763** and expectations ” (emphasis supplied) ) . 226 Subsequently, in Sierra Club v. Costle, the Court noted, in upholding the standard: “we find it informative that the vendors of FGD equipment corroborate the achievability of the standard.” 227 Linde and BASF offer performance guarantees for carbon capture technology. The two companies are jointly marketing new, advanced technology for capturing CO 2 from low pressure gas streams in power or chemical plants. In product literature , 228 they note that Linde will provide a turn
- key carbon capture plant using a scrubbing process and solvents developed by BASF, one of the world’s leading technical supplier s for gas treatment. They further note that:

The captured carbon dioxide can be used commercially for example for EOR (enhanced oil recovery) or as a building block for the production of urea. Alternatively it can be stored underground as a
226 See also Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375, 401
- 02 (D.C. Cir. 1973) (“It would have been entirely appropriate if the Administrator had justified the standards ... on testimony from experts and vendors made part of the record.”) . 227 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 guarantees are an indicia of availability and achievability of a technology
-based standard since, notwithstanding a desire to promote sales, “a manufacturer would risk a considerable loss of reputation if its technology could not fulfill a mandate that it had persuaded EPA to adopt”). 197 www.interme diates.basf.com/chemicals/web/gas
treatment/en/function/conversions:/publish/content/products
- andindustries/gas
- treatment/images/Linde_and_BASF
Flue_Gas_Carbon_Capture_Plants.pdf .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **232** of **763** carbon 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 company, 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
... Optimiz ed total and operational costs for the owner. (emphasis added) In addition, other well - established companies that either offer technologies that are actively marketed for CO 2 capture from fossil fuel
- fired power plants or that develop those power plants , have publicly expressed confidence in the technical feasibility of carbon capture . For example, Fluor has developed patented CO 2 recovery technologies to help its clients redu ce GHG emissions. The Fluor product literature 229 specifically points to the Econamine FG Plus SM (EFG+) process , which uses an amine solvent to capture and produce food grade CO 2 from post combustion sources. The literature further note s that EFG+ is also used for carbon capture and sequestration projects , 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 power plant's

229 www.fluor. com/client
-markets/energy
- chemicals/Pages/carbon
capture.aspx***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **233** of **763** unique site requirements, flue gas conditions, and operating parameters . Fluor has also published an article titled “Commercially Available CO 2 Capture Technology” in which it describe s the EFG+ technology. 230 The article note s, “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 to address the GHG effect but to provide an economic source of CO 2 for use in enhanced oil recovery and i ndustrial 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 monoethanolamine (MEA) -based absorbent , KS - 1TM solvent requires less solvent circulation to capture the CO 2 and less energy to recover the captured CO 2 . In addition, Shell has developed the CANSOLV CO 2 Capture System, which Shell describes i n its product literature 231 a s a world leading amine based CO 2 capture technology that is ideal for use in fossil fuel
- fired power plants where enormous amounts
230 http://www.powermag.com/commercially
- available
- co2
- capture technology/ 231 http:// www.shell.com/global/products
- services/solutions
- for businesses/globalsolutions/shell
- cansolv/shell
- cansolvsolutions/co2
- capture.html***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **234** of **763** of CO 2 are generated. The company also note s that the technology can help refiners, utilities , and other industries lower their carbon intensity and meet stringent GHG abatement regulations 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 un likely 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 . 232 However, this suggestion is inconsistent with the performance guarantees offered for other air pollution c ontrol equipment. Particulate matter (PM) is controlled in the flue gas stream of a coal
- fired power plant using fabric filters or electrostatic precipitators (ESP). The captured PM is then moved using PM/ash handling systems and is then transported for storage or re - use. It is unlikely that a fabric filter or ESP vendor would provide a performance guarantee for “the system as a whole .” Similarly, a wet - FGD scrubber vendor would not be expected to provide a performance guarantee for handling, transportati on , and re - use of scrubber solids for gypsum wallboard manufacturing. CO 2 capture, transportation, and storage should, similarly, not be viewed as a single technology. Rather, these should be viewed as

232 Comments of Murray Energy, p. 73 , EPA- HQ - OAR- 2013
- 0495
- 10046***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **235** of **763** components of an overall system of emission reduction. Different companies will have expertise in each of these components , but it is unlikely that a single technology vendor would provide a guarantee for “the system as a whole .” 2. Academic and Other L iterature Climate change mitigation options

– including CCS - are the subject of great academic interest , and there is a large body of academic literature on the se options and their technical feasibility . In addition, other research organizations (e.g., U.S. national laboratories and others) have also published studies on these subjects that demonstrate the availability of these technologies . A compendium of relevant literature is provided in a Technical Support Document available in the rulemaking docket. 233 3 . Additional S tatements by Technology Devel opers The discussion above of vendor guarantees, positive statements by industry officials, and the academic literature supports the EPA’s determination that partial CCS is adequately demonstrated to be technically feasible. Industry officials have made additional positive statements in conjunction with facilities that received DOE assistance under EPAct05 or the IRC

233 Technical Support Document

– “Literature Survey of Carbon Capture Technology”, available in the rulemaking docket (Docket ID: EPA- HQ - OAR- 2013
- 0495).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **236** of **763** section 48A tax credit . These statements provide further, although not necessary, support . For example, Southern Company’s Mississippi Power has 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 referred to as SelexolTM. The SelexolTM process is a commercial technology that uses proprietary solvents, but is based 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 and operation of the carbon capture equipment incorporated into the Plant’s design is manageable. 234 And ...The carbon capture equipment and processes proposed in this project have been in commercial use in the chemical industry for decades and pose little technology risk . 235 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

234 Testimony of Thomas O. Anderson, Vice President, Generation Development for Mississippi Power, MS Public Service Commission Docket 2009
-UA- 14 at 22 (Dec. 7, 2009 ). 235 Mississippi Power Company, Kemper County IGCC Certificate Filing, Updated Design, Description and Cost of Kemper IGCC Project, Mississippi Public Service Commission (MPSC) DOCKET NO. 2009
-UA- 0014, filed December 7, 2009.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **237** of **763** the United States and quite honestly for the rest of the world going forward . 236 Some commenters have claimed that CCS technology is not technically feasible , and some further assert that vendors do not offer performance guarantees. For example, Alstom commented:

The EPA referenced projects fail to meet the 'technically feasible' criteria. These technologies are not operating at significant scale at any site as of the rule publication. We do not support mandating technology based on proposed projects (many of which may never be built). 237 As discussed above, vendors do in fact offer performance guarantees . We further note that , as noted above, Boundary Dam Unit #3 is a full
- scale project that is successfully implementing full CCS with post
- combustion capture, and Dakota Gasification is likewise a full
- scale commercial operation that is successfully implementing pre
- combustion CCS technology. Moreover, as we explain above, this technology and performance is transferable to the steam electric generating sector. In addition, as noted above, technology providers and technology end users have expressed confidence in the availability and performance of CCS technology . 238

236 American Electric Power Co Inc AEP Q2 2011 Earnings Call Transcript, Morningstar, http://www.morningstar.com/earnings/28688913
- american
- electric
power - co - incaep
- q2
- 2011
- earnings
- call - transcript.aspx. 237 Alstom Comments, p. 3. 238 We note that before filing comments for this rule asserting that CCS is not technically feasible, Alstom issued public***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **238** of **763** G. Response to Key Comments on the Adequacy of the Technical Feasibility Demonstration 1. Commercial Availability Some commenters asserted that CCS cannot be considered the BSER because it is not commercially available. There is no requirement, as part of the BSER determination, that the EPA finds that the technology in question is “commercially available .” As we described in the January 2014 proposal, the D.C. Circuit has explained that a standard of performance is “achievable” if a technology or other system of emission reduction can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard , and that there is no requirement that the technology “mus t 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 available through vendors who provide performance guarantees, which indicates that in fact, CCS is commercially available, which adds to the statements that, like the other industry offic ials quoted above, affirmed that CCS is technically feasible. According to an Alstom Power press release, Alstom President Phillipe Joubert, referencing results from an internal Alstom study, stated at an industry meeting : “We can now be confident that carbon capture technology (CCS) works and that it is cost effective”. http://www.alstom.com/press
- centre/2011/6/2011
- 06
- 16
- CCS - cost competiveness/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **239** of **763** evidence that the technology is adequately demonstrated to be technically fea sible. In sum, “[t]he capture and CO 2 compression technologies have commercial operating experience with demonstrated ability for high reliability.” 239 2. Must a technology or system of emission reduction be in full scale use to be considered demonstrated ? Commenters maintained that the EPA can only show that a BSER is “adequately demonstrated” using operating data from the technology or system of emission reduction itself . This is mistaken. Since the very inception of the CAA section 111 program, courts have noted that “[i]t would have been entirely appropriate if the Administrator had justified the standard, not on the basis of tests on existing sources or old test data in the literature, but on extrapolations from this data, on a reasoned basis responsive t o comments, and on testimony from experts and vendors ....” Portland Cement v. Ruckelshaus , 486 F. 2d at 401
- 02 . 241

239 “ Co st and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3”, DOE/NETL - 2015/1723 ( July 2015) at p. 36 . 241 More recently, the D.C. Circuit stated: Our prior decisions relating to technology- forcing standards are no bar to this conclusion. We recognize here, as we have recognized in the past, that an agency may base a standard or mandate on future technology when there exists a rational connection***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **240** of **763** 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 bas ed on operation of component 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 integrated at Boundary Dam: post - combustion full CCS is being utilized at a steam electric fossil fuel
- fired plant, with captured carbon being transported via dedicated pipeline to both sequestration and EOR sites . All components are likewise demonstrated for pre
combustion full CCS at the Dakota Gas IGCC facility, except that the facility does not generate electricity, a distinction without a difference for this purpose (see S ection V.E.2.a above ).
between the regulatory target and the presumed innovation. API v. EPA, 706 F. 3d at 480 (D.C. Cir 2013) ( citing the section 111 case Sierra Club v. Costle , 657 F. 2d at 364 ). The Senate Report to the original section 111 likewise makes clear that it was not intended that the technology “must be in actual routine use somewhere.” Rather, the question was whether the technology would be available for installation in new plants. S. Rep. No.9 1
- 1196, 91 st Cong., 2d Sess. 16 (1970). 242 See , e.g . , Comments of UARG p. 5 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **241** of **763** The short of it is that the “EPA does have authority to hold the industry to a standard of improved design and operational advances, so long as there is substantial evidence that such improvements are feasible and will produce the improved performance nece ssary 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 P ilot and Demonstration P rojects Commenters maintained that EPA had no basis for maintaining that pilot and demonstration plant operations showed that CCS was adequately demonstrated. This is mistaken. In a 1981 decision, Sierra Club v. Costle , the D.C. Circuit explained that data from pi lot - 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 explain the necessary steps involved in scaling up a technology and how any***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **242** of **763** obstacles may reasonably be surmounted when doing so. 243 The EPA has done so here. Most obviously, the final standard reflects experience of full - scale operation of post
- combustion carbon capture. Pre combustion carbon capture is likewise demonstrated at full
scale. Second, the record explains in detail how CCS can be implemented at full
- scale. The NETL cost and performance reports, indeed, contain hundreds of pages of detailed, documented explanation of how CCS can be implemented at full
scale for both utility boile r and IGCC facilities. See, for example, the detailed description of the following systems projected to be needed for a new supercritical PC boiler to capture CO 2 : coal and sorbent receiving and storage, ste am generator and ancillaries, NOX control system, particulate control, flue gas desulfurization, flue gas system, CO 2 recovery facility, steam turbine generator system, balance of plant, and

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 performance 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 pilot plant information to justify technology
-based standard 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 Ci r. 1976)(same ) .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **243** of **763** accessory electric plant, and instrumentation and control systems. 244 It is important to note that, while some commenters challenged EPA’s use of costs in the DOE/NETL cost and performance reports, commenters did not challenge the technical methodology in the work. In addition, the AEP FEED study indicates how the development scale post - combustion CCS could be success fully scaled up to full - scale operation. See Section V.D.3.b above. Tenaska Trailblazer Partners, LLC also prepared a FEED study245 for the carbon capture portion of the previously proposed Trailblazer Energy Center, a 760 MW SCPC EGU that was proposed to include 85 to 90 percent CO 2 post - combustion capture. Tenaska selected the Fluor Econamine FG Plus SM technology and contracted Fluor to conduct the FEED study. One of the goals of the FEED study was to “ [c] onfirm that scale up to a large commercial size is achievable .” Tenaska ultimately concluded that the study had achieved its objectives resulting in

“ [c] onfirmation that the technology can be scaled up to
constructable design at commercial size through (1) process and
244 Cost and Performance Baseline fo r Fossil Energy Plants Volume 1 : Bituminous Coal and Natural Gas to Electricity; Revision 2a, pp. 57 - 74. 245 Final front
- end engineering design (FEED) study report ”, available at: www.globalccsinstitute.com/publications/tenaska
trailblazer
- front - end- engineering
- design
- feed- study .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **244** of **763** discipline engineering design and CFD (computational 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 adding CCS systems to fossil fuel
- fired power plants. Some of these statements come from high government officials. Some commenters argued that the EPA minimized

– or even ignored

– these publically voiced concerns in the discussion presented 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 different context: namely, implementing full CCS, or retrofitting CCS onto
existing power plants . For example, i n the Final Report of the President’s CCS Task Force, it was noted that “integration 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
- effective deployment of CO 2 capture.” 246 This statement

– and most of the statements in

246 Report o f the Interagency Task Force on Carbon Capture and Storage (August 2010), page 28. See also DOE Carbon Capture Website: “First generat ion CO 2 capture technologies are currently being used in various industrial applications. However, in their current state of development, these technologies are not ready for implementation on coal
-based power plants because they have not been demonstrate d at appropriate scale, requisite approximately one
- third of the plant’s steam power to operate, and are cost prohibitive . ” (Dec 2010); and Testimony of Dr. S.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **245** of **763** this vein

– are in reference to implementation of full CCS systems that capture more than 90 percent of the CO 2 and many reference widespread implementation of such technology. The EPA has addressed the concerns regarding “significant cost” by finalizing a standard that relies on partial CCS which we show, in this preamble and in the supporting record, can be implemented at a reasonable , non - exorbitant cost. The Boundary Dam facility, in particular, demonstrates that the complexities of implementing CCS

– even full CCS

– can be overcome. Concerns regarding “operating issues” are also often associated with implementation of full CCS

– and often with implementation of full CCS as a retrofit to an existing source. Implementation of CCS at some existing sources may be challenging because of space limitations. That should 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 existing facility can be challenging even if there is adequate space because the positioning of the equipment may be awkward when it must be Julio Friedmann, Deputy Asst. Secretary of Energy for Clean Coal, US Dept. of Ene rgy, before the Subcommittee on Oversight and Investigations Committee on Energy and Commerce (Feb. 11, 2014): CCS technologies at new coal
- fired plants would result in "something like a 70 to 80 percent increase on the wholesale price of electricity."***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **246** of **763** constructed to fit with the existing equipment at the plant. Some commenters noted the challenges of diverting steam from the plant’s steam cycle. Again, that is primarily an issue with full CCS implementation as a retrofit to an existing sou rce. Consideration of steam requirements for solvent regeneration can be factored into the design of a new facility. We also note that issues of integration with the plant’s steam cycle are less challenging when implementing partial CCS. Some commenters no ted conclusions and statements from the CCS Task Force report as contradictory to EPA’s determination of that partial CCS is technically feasible 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 overcome the barriers to the widespread, cost
- effective deployment of CCS by 2020. Implicit in all of the conclusions, recommendations, and statements of that final report is a goal of widespread implementation of full CCS

– including retrofits of existing sources. This final action does not require

– nor does it envision

– the near term widespread implementation of full CCS. On the contrary, as we have noted several times in this preamble, the E PA and others predict that very few , if any, new coal - fired steam generating EGUs will be built in the near term.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **247** of **763** Thus, the EPA has provided an ample record supporting its finding that partial CCS is feasible at full
- scale. As in Sierra Club , the EPA has presented evidence from full
- scale operation, smaller scale installations, and reasonable, corroborated technical explanations of how the BSER can be successfully operated at full scale. See 657 F. 2d at 380, 382. Indeed, the EPA has more evidence here, as the baghouse standard in Sierra Club was justified based largely on less
- than - full - scale operation. See 657 F. 2d at 380 (there was only “limited data from one full scale commercial sized operation”) , 376 (“the baghouses surveyed were installe d at small plants”), and 341
n. 157 ; see also S ection V.L , explaining why CCS is a more developed technology than FGD scrubbers were at the inception of the 1971 NSPS for this industry. H. Consideration of Costs CAA section 111(a) defines “standard of performance” as an emission standard that reflects the best system of emission reduction that is adequately demonstrated, “taking into account [among other things] the cost of achieving such reduction.” Based on cons ideration of relevant cost metrics in the context of current market conditions, the EPA concludes that the costs associated with the final standard are reasonable. In reaching this determination, the EPA considered a host of different cost metrics, each of which illuminated a***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **248** of **763** particular aspect of cost consideration, and each of which demonstrated that the costs of the final standard are reasonable. The EPA evaluated capital costs on a per -plant basis, responding to public comment that noted the particular
s ignificance 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 national, overall cost impacts of the standard . The EPA found that the anticipated cost impacts are similar to those in other promulgated NSPS

– including for this industry
- that have been upheld by the D.C. Circuit. The costs are also comparable to those of other base load technologi es that might be selected on comparable energy portfolio diversity grounds. In addition, in an analysis of the impacts of adding the BSER control technology to a single illustrative facility, the EPA concluded that the marginal monetized social benefits exceed marginal costs under a range of assumptions . Finally, the EPA does not anticipate any significant overall nationwide costs or cost impacts on consumers. Accordingly, after considering costs from a range of different perspectives, the EPA conclude s that the costs of the final standard are reasonable. 1. Rationale at P roposal At proposal, the EPA evaluate d the costs of new coal - fired EGUs implementing full (90 percent) and partial CCS . The EPA***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **249** of **763** compared the predicted LCOE of those units against the LCOE of other new dispatchable technologies often considered for new base load power with fuel diversity , primarily including a new nuclear plant , as well as a new biomass
- fired EGU. See 79 FR at 1475
- 78. The l evelized cost for a new steam EGU implementing 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 1,100 lb CO 2 /MWh g , reflecting a new steam EGU implementing partial CCS, could be achieved at reasonable cost based on a comparison of the projected LCOE associated with achieving this standard with the alternative dispatchabl e technologies just mentioned . In the January 2014 proposal, the EPA used LCOE projections for new fossil fuel
- fired EGUs from a series of studies conducted by the DOE NETL. These studies

– the “cost and performance studies”

– detail expected costs and performance for a range of technology options both with and without CCS. 247 The EPA used LCOE

247 For the cost estimates in the January 2014 proposal, the EPA used costs for new SCPC and IGCC units utilizing bituminous coal from the reports “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity” , Revision 2, Report DOE/NETL

– 2010/1397 (November 2010) and “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture”, DOE/NETL

– 2011/1498, May 27, 2011. Additional cost and performance information can be found in additional volumes that are available at***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **250** of **763** 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 implement partial CCS were reasonable because a segment of the 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 benefits, loan guarantees, and direct expenditures, and the opportunity to generate income from sale of captured CO 2 for EOR . Id. at 1478
- 80. The EPA noted that the proposed standard was not 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 electricity suppliers might include new coal - fired generating sources in their generation portfolio, and would pay a premium to do so. Id. at 1478. 2. Brief Summary of C ost Considerations Under CAA Section 111 As explained above, CAA section 111(a) directs the EPA to

“ tak[e] into account the cost” of achieving reductions in http://www.netl.doe.gov/research/energy
- analysis/energy
baseline
- studies***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **251** of **763** determining if a particular system of emission reduction is the best that is adequately demonstrated. The statute does not provide further guidance on how costs should be considered, thus affording the EPA considerable discretion in choosing a means of cost consideration. In addition, it should be noted that i n evaluating the reasonableness of costs , the D.C. Circuit has upheld application of a variety of metrics, such as the amount of control costs or product price increases . See Section III.H.3 .( b ) . ( 1) above. Following the directive of CAA s ection 111(a) and applicable precedent, the EPA evaluated relevant metrics and context in considering the reasonableness of the regulation’s costs. The EPA’s findings demonstrate that the costs of the selected f inal standard are reasonable. 3. Current Context The EIA projects that few new coal - fired EGUs will be constructed over the coming decade and that those that are built will apply CCS , reflecting the broad consensus of government, academic, and industry forecasters . 248 The primary reasons for

248 Even in its sensitivity analysis that assumes higher natural gas prices and electricity demand, EIA does not project any additional coal 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 assume GHGs emission limitations. EIA, “Annual Energy Outlook 2015,”***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **252** of **763** this projected trend include low electricity demand growth , highly competitive natural gas prices, and increases in the supply of renewable energy. In particular, U . S . electricity 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
- fired electricity generating capacity that is constructed through 2030 , 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 utilities 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 particular generation technology, they do indicate the types of new generating technologies that a utility would consider for new generating capacity. The EPA’s survey of recent IRPs demonstrates that across the nation, utilities are not actively considering

DOE/EIA
- 0383(2015), April 2015, “[v]ery little unplanned coal
fired capacity is added across all the AEO 2015 cases”, p. 26. 249 EIA, “Annual Energy Outlook 201 5 ,” DOE/EIA
- 0383(2015), April 2015, p. 8 . 250 Integrated Planning Model (IPM) run by EPA (v. 5.15) Base Case, available at www.epa.gov/powersectormodeling/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **253** of **763** 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 today , except perhaps in certain limited circumstances. In particular, commenters suggested that some developers might choose to build a new coal
- fired EGU, despite its not being cost competitive , in order to achieve or maintain “ fuel diversity . ” Fuel diversity could provide important value by
serving as a hedge against the possibility that future 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. The Integrated Resource Plan TSD 251 notes examples where the goal of fuel diversity was considered in IRPs ; in many cases, these plans considered new generation that would not rely on natural gas. In particular, s everal utilities that considered fuel diversity in developing their IRPs include d new nuclear generation as a potential future generation strategy.

251 Technical Support Document
- “Review of Electric Utility Integrated Resource Plans” (May 2015 ), available in the rulemaking docket EPA
- HQ - OAR- 2 013
- 0495.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **254** of **763** In addition, the EPA recognizes that there may be interest in constructing a new combined
-purpose coal - fired facility that would generate power as well as produce chemicals or CO 2 for use in EOR projects . These facilities would similarly provide additional value due to the revenue streams from saleable chemical products or CO 2 . 252 As demonstrated below , the agency carefully considered the reasonableness of costs in identifying a standard that allows a path forward for such projects and rejects more stringent options that would impose potentially excessive costs. In fact, based on this careful consideration of costs, the EPA is finalizing a substantially lower cost standard than the one we proposed. At the same time, we note the unusual circumstances presented here, where the record, and indeed simple consideration of electricity market economics , demonstrate s that
non - economic factors such as fuel diversity are likely to drive any construction of new coal - fired generation . See also RIA chapter 4 (documenting that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily NGCC units, because of existing and expected market conditions). Under these
252 The EPA may, of course, consider revenues generated 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
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– Do Not Cite, Quote or Release During Review *** Page **255** of **7 63**  circumstances, the EPA’s consideration of costs takes into account that higher costs can be viewed as reasonable when costs are not a paramount factor in new coal capacity decisions. 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 considerations. 253 The EPA has reasonably cabined its consideration of costs by examining costs for comparable non -NGCC base load dispatchable technologies, as well as by considering capital costs and other cost metrics. 254 This cost - reasonable standard will preserve the opportunity for such projects while driving new technology deployment. 255 4. Consideration of Capital Costs

253 See , e.g . , Comments of Murray Energy, pp. 79
- 80. 254 Indeed, the EPA is not only adopting a standard predicated on a lower rate of carbon capture than proposed, but also rejecting full CCS for reasons of cost. See S ection V. P below. Thus, although the EPA has reasonably taken into account the current economic posture of the industry whereby new capacity is not cost - competitive and so would be added for non - economic reasons, it is not using that fact to negate consideration of cost here. See also S ection V. I.4 below responding to comments that the incremental cost of partial CCS could prove the difference between constructing and not constructing new coal capacity. 255 In this rulemaking, our determination that the costs are reasonable means that the costs meet the cost standard in the case law no matter how that standard is articulated, this is, whether the cost standard is articulated through the terms that the case law uses, e.g., “exorbitant,” “excessive,” etc., or through the term we use for convenience, “reasonableness .”***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **256** of **763** As noted above, CAA s ection 111 does not mandate any particular method for evaluating costs, leaving the EPA with significant discretion as to how to do so. One method 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 proposal and, as discussed further below, the LCOE metric relied upon at proposal and in this final rulemaking incorporates and fully reflects capital costs . 256 Nonetheless, extensive comment from industry representatives and others noted persuasively that fossil
- steam units are very capital
- intensive projects and recommended that a separate metric, solely of capital costs , be considered by the EPA in evaluating the final standard’s costs . Accordingly , the EPA has considered the final standard’s impact on the capital costs of new fossil
- steam generation . The EPA has determined that the incremental capital costs of the final standard are reasonable because they are comparable to those in prior regulations and to industry experience , and because the fossil steam electric power industry has been shown to be able to successfully absorb capital costs of this magnitude in the past . 256 See RIA chapter 4. 5 .4 and Fig. 4
- 3 ; see also “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 ( July 2015) p. 17.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **257** of **763** Prior new source performance standards for new fossil steam generation units have had significant

– yet manageable

– impacts on the capital costs of construction. The EPA estimated that the costs for the 1971 NSPS for coal
- fired EGU s were $19M for a 600 MW plant, consisting of $3.6M for particulate matter controls, $14.4M for sulfur dioxide controls, and $1M for nitrogen oxides controls, representing a 15.8 percent increase in capital costs above the $120M cost of the plant. See 1972 Supplemental Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld 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 4 40. In reviewing the 1978 NSPS for coal - fired EGU s, the D.C. Circuit recognized that “EPA estimates that utilities will have to spend tens of billions of dollars by 1995 on pollution control under the new NSPS” and that “[c]onsumers will ultimately bear these costs.” Sierra Club , 657 F.2d at 314. The court nonetheless upheld EPA’s determination that the standard was reasonable . Id. at 410. The cost and investment impact s of the 1978 NSPS on electric utilities were subsequently evaluated in a 1982***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **258** of **763** Congressional Budget Office (CBO) retrospective study . 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 led to an estimated 37.5 to 45 percent increase in capital costs for coal
fired power plant installation between 1971 and 1980 . 259 The study retrospectively confirmed the EPA’s conclusion that imposition of these costs was reasonable , finding that

“ utilities with commitments to pollution control tend to fare no better and no worse than all electric utilities in general.” 260 In assessing the capital cost impacts of the suite of 1970 s 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 In NSPS standards for other sectors, the EPA's determination that capital cost increases were reasonable has

257 Congressional Budget Office report, “The Clean Air Act, the Electric Utilities, and the Coal Market”, April 1982, p. 10
- 11, 23. 258 Id. at 10
- 11. 259 Id. at 22. 260 Id. at xvi. 261 Id.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **259** of **763** 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 , al though the rule was remande d 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 standards and the EPA’s consideration of costs , noting that “[t]he industry has not shown inability to adjust itself in a healthy economic 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 individual unit basis to those projected for the present standard. We predict that the incremental costs of control for a new highly efficient SCPC unit to meet the final emission limitation of 1,400 lb CO 2 /MWh - 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 reasonableness of EPA’s cost projections here. 263 We estimate that a new SCPC EGU using low rank coal (subbituminous coal or dried lignite) would incur a capital cost increase of 23 percent to meet the final standard. See “Achievability of the Standard for Newly Constructed Steam Generating EGUs” technical support document available in the rulemaking docket.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **260** of **763 Table**  **7 . Comparison of**  **estimated capital costs for a new SCPC**  **and a new SCPC meeting the final standard of performance. 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 gas 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 SCPC. A compliant IGCC unit co
- firing natural gas is predicted to have Total Overnight Cost of $3,036/kW

– an approximately 21.1 percent increase in capital over the uncontroll ed SCPC unit. 5. Consideration of Costs Based on Levelized Cost of E lectricity As in the proposal, the EPA also considered the reasonableness of costs by evaluating the LCOE associated with the final standard. The LCOE is a commonly used economic metric that takes into account all costs to construct and operate a new power plant over an assumed time period and an assumed capacity factor. The LCOE is a summary metric, which expresses the full
264 Exhibit A
- 3 (p. 18); “Cost and Performance Baseline for Fossil Energy Plants Supp lement: Sensitivity to CO 2 Capture Rate in Coal
- Fired Power Plants”, DOE/NETL
- 2015/1720 (June 2015).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **261** of **763** 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. While capital cost is a useful and relevant metric for capital
- intensive 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 without CCS) from DOE/NETL reports detailing the results of studies evaluating the costs and performance of such units. For non
fossil dispatchable generating sources, the EPA relied on LCOE projections from EIA AEO 2013 . For this final action, the EPA is relying on updated costs from the same sources. The NETL has provided updated cost and performance information in recently published revisions of reports used in the January 2014 proposal. 265 The updated SCPC cases in the reports include up
- to date cost and performance information from recent vendor quotes
265 “Cost and Performance Baseline for Fossil Energy Plants: Volume 1a” Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3, U.S. DOE NETL report ( 2015) and “Cost and Performance Baseline for Fossil Energy Plants: Volume 1b: Bituminous Coal (IGCC) to Electricity, Revision 2

– Year Dollar Update, U.S. DOE NETL report (2015). Both reports are available at www.netl.doe.gov/research/energy
- analysis/energy-baseline
studies***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **262** of **763** and implementation of the Shell Cansolv post - combustion capture process – the process that is currently being utilized at the Boundary Dam #3 facility. The IGCC cost and performance results in the updated reports utilize vendor quotes from the 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 financial assumptions for cases that include CCS. 266 Using information from those reports, the DOE/NETL prepared a separate report summarizing a study that evaluated 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 are discussed in more detail in section V.I.2. b and d . In evaluating costs for the final standards in this action, the EPA relied primarily on the updated NETL LCOE projections for new fossil fuel
- fired EGUs provided in the reports described above and on the LCOE projections for non
- fossil, dispatchable generating options from
266 Cost and Performance Baseline for Fossil Energy Plants 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 Plants 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/energy
baseline
- studies.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **263** of **763** the EIA’s AEO 2015 . 268 Here, the EPA compared the LCOE of the final standard to the LCOE of analogous potential sources of intermediate and base load power. This comparison demonstrated 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 biomass generation, which similarly provide both base load power and fuel diversity, have comparable LCOE . The EPA concludes that an evaluation of the LCOE also demonstrates that the costs 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 therefore is dependent on the project’s capital costs, the fixed and variable operating and maintenan ce (O&M) costs, the fuel costs, the costs 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. For example,
268 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm 269 See, e.g. “Cost and Performance Baseline for Fossil 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
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– Do Not Cite, Quote or Release During Review *** Page **264** of **763** the LCOE for a new supercriti cal 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 comparably sized new NGCC facility which would require less capital investment but would be more influenced by assumed fuel costs. b. Use of the LCOE . The utility industry and electricity sector regulators 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 appropriate where the facilities being compared would serve load in a similar manner. The value of generation, as reflected in the wholesale electricity price, can vary seasonally and over the course of a day. In addition, electricity generation techno logies differ on dimensions other than just cost, such as ramping efficiency, 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 accordingly cost compari sons between two different technologies are most appropriate and insightful when the technologies align along these other dimensions. I solating a comparison of technologies based on their LCOE is appropriate when they can be assumed to provide similar service s and similar value s of electricity generated.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **265** of **763** As we indicated in the proposal, we evaluated publicly available IRPs and other available information (such as public announcements) to determine the types of technologies that utilities are considering as options for new generating 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 are interested in a range of technologi es that can be used to provide or preserve fuel diversity within the utilities’ respective generating fleets. 271 , 272 The options for dispatchable generation

270 See also discussion at V.C.3 above. The IRPs do not provide an indication of the ut ility’s intention to pursue a particular generation technology. However, the IRPs do provide an indication of the types of new generating technologies that the utility would consider for new generating capacity. 271 See, e.g. the 2014 IRP of Dominion Virgini a Power: With those factors in mind, the 2014 Plan presents two paths forward for resource expansion: a Base Plan, designed using least - cost planning methods and consistent with the requirements of Rule R8
- 60 for utility plans to provide "reliable electri c utility service at least cost over the planning period;" 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 provides the important benefits of greater fuel diversity and lower carbon intensity. Therefore, the Company will continue reasonable development of the more diverse and lower carbon intensive options in the Fue l Diversity Plan and will be ready to implement them as conditions warrant
... . The Fuel Diversity Plan places a greater reliance on generation sources with little or no carbon emissions and is less reliant on natural gas. While following the resource expansi on scenario in the least - cost Base Plan, the Company will continue evaluation and reasonable***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **266** of **763** development efforts for the following projects identified 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 power and continue s to actively develop the project. Our customers 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 construction of North Anna Unit 3 will not be made until after the Company receives a Combined Operating License or COL from the 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 2028. If constructed, the project would provide a dramatic boost to the regional economy. • Additional reliance on renewable energy, including 247 megawatts of onshore wind capacity at sites in western Virginia and a 12 megawatt offs hore wind demonstration project by 2018. • An additional 559 megawatts of nameplate solar capacity, including several new Company
- owned photovoltaic CPV) installations. Solar PV costs have declined significantly in recent years, making utility
- scale solar much more cost effective than distributed solar, and continuing technological development, in which the Company is participating, may allow it to become a more cost - effective source of intermittent generation in the future.” cover letter for 2014 IRP
- https://www.dom.com/library/domcom/pdfs/corporate/integrated
resource -planning/va
- irp
- 2014.pdf 272 Another example are the recent statements of officials 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 conference in October [2010], a position that Tri
- State representatives say remains. “We will pick our technology once policy certainty comes about,” he added. ...Longer - term forecasts are based on assumptions that may or may not prove well
- founded. Because of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **267** of **763** that can provide intermediate or base
- load power and fuel diversity would include new fossil steam unit s, new nuclear power, and biomass
- fired generation. 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 operated 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 plant with that of a peaking natural gas
- fired simple cycle turbine. Similarly, it may not be appropriate to compare LCOE for dispatchable 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., generating this uncertainty, Tri
- State believes it must retain options for all fuels and technologies. “We will not take anything off the table,” [Tri
- State spokesman Lee] Boughey said. That includes coal. “Coal is an affordable and plentiful resource, but it does come with challenges

– and we are looking to different technology that can address some of those challenges while continuing to provide a reliable and affordable power supply,” Boughey said. “Some critics believe we shouldn’t be looking at resource options that include coal, and even nuclear technology,” Boughey added. “We believe it would be irresponsible not to consider these fuels or technologies a s part of an affordable, reliable and responsible resource portfolio.”***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **268** of **763** sources that cannot be reli ably ramped up or down to meet demand, e.g., wind, solar. )
c. Reasonableness of costs based on LCOE . An examination of the LCOE of analogous sources of base load , dispatchable power shows that the final standard’s LCOE is comparable to that of other sources, as shown in Table 8 below . As mentioned earlier and discussed in further detail below, these estimates rely most heavily on DOE/NETL cost project ions for fossil fuel generating technologies and on the updated EIA AEO 2015 for non - fossil generation technologies. Recent estimates from Lazard273 , 274 are also provide d for nuclear and biomass generation options. **Table 8**  **. Predicted Cost and CO** **2 Emission Levels for a Range of**  **Potential New Generation Technologies 275** 

273 Lazard’s Levelized Cost of Energy Analysis

– Version 8.0; September 2014; available at: http://www.lazard.com/media/1777/levelized_cost_of_energy_
- _version_80.pdf and in the rulemaki ng 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 sector clients with adviso ry services regarding M&A, financing, and other strategic matters. The group is active in all areas of the traditional and alternative energy industries, including regulated utilities, independent power producers, advanced transportation technologies, renewable energy technologies, meters, smart grid and energy efficiency technologies, and infrastructure. http://www.marketwatch.com/story/lazard
releases - new- levelized
- cost - of - energy- analysis
- 2014
- 09
- 18 275 LCOE cost estimates for SCPC and IGCC cases come from “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 22, 2015). Cost and performance for low rank SCPC is adapted from “Cost and Performance Baseline for***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **269** of **763** 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 Biomass (EIA) 276

- 94

– 113 Biomass (Lazard)
- 87
- 116 IGCC 1 , 430 94
- 120 NGCC 1,000 52

– 86** * The LCOE range s presented in Table 8 include an uncertainty of

- 15%/+30% on capital costs for SCPC and IGCC cases and an uncertainty of
- 10%/+30% on capital costs for nuclear and biomass cases from EIA . This reflects information provided by EIA. Nuclear staff experts expect that nuclear plants currently under construction would not have capital costs under estimates and that one could expe ct to see a 30% “upside” variation in capital cost. There is also insufficient market data to get a good statistical range of potential capital cost variation (i.e. only 2 plants under construction, neither complete). The nuclear Fossil Energy Plants Volume 3 Executive Summary: Low 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 New Generation Resources in the Annual Energy Outlook 2015”, June 2015, www.eia.gov/foreca sts/aeo/pdf/electricity_generation.pdf. LCOE cost estimates for NGCC technology are EPA estimates based on a range of potential natural gas prices. 276 Table 8 includes LCOE figures for biomass
- fired generation, a potential sources of dispatchable base load power that is not fueled by natural gas. The EPA includes this information for completeness, while noting that biomass
- fired units in operation in the U.S. are smaller scale and thus are not as robust 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.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **270** of **763** cost estimates from Lazard likewise reflect the range 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 SCPC unit without capture. 277 ** Thi s range represents a natural gas price from $ 5 /MMBtu to $10/MMBtu. As shown in Table 8 , we project that the LCOE for new 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 gas to provide new base load power. This is the case for new units firing bituminous and subbituminous coals and dried lignite. This is another demonstration that the costs of the final standard are reasonable be cause nuclear and fossil steam generation each would serve an analogous role in adding dispatchable base load generation diversity

– or at least non -NGCC alternatives
- to a power provider’s portfolio; hence, they are reasonably viewed as comparable alternatives. 278 As previously mentioned, the DOE/NETL assumed conventional financing for cases without CCS and assumed high
- risk financing for case s with some level of CCS. Specifically a high
- risk
277 “Cost and Performance Baseline for Fossil Energy Plants Supplement : Sensitivity to CO 2 Capture Rate in Coal
- Fired Power Plants”, DOE/NETL
- 2015/1720 (June 2015) at p. 18. 278 LCOE comparisons of reasonably available compliance 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 than SCPC with partial CCS, or of comparable cost.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **271** of **763** financial structure resulting in a capital charge factor (CCF) of 0.124 is used in the study to evaluate the c osts of all cases with CO 2 captu re (non - capture case uses a conventional financial structure with a CCF of 0.116). 279 As a comparison of how this affects the resulting DOE/NETL costs, a new SCPC utilizing 16 percent partial CCS is projected to have an LCOE of $99/MWh (including transportation and storage costs; does not include the range for uncertainty). That projected LCOE includes the “high risk financial assumptions”. If the LCOE for that unit were to be calculated using the “conventional financing assumptions”, the resulting LCOE would be $94/MWh. This approach is in contrast to that taken by the EIA which applies a 3
-percentage -point cost of capital premium (the ‘climate uncertainty adder’) to non
- captu re coal plants to reflect the market reaction to potential future GHG regulation. Under current and anticipated market conditions, power providers that are considering costs alone in choosing 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 IRPs indicate that utilities are considering and selecting technologies that

279 “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal
- Fired Power Plants”, DOE/NETL
- 2015/1720 (June 2015) at p. 7.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **272** of **763** could provide or preserve fuel diversity within generating 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 facilities and by IRPs that include new nuclear generation in their plans. In general , fossil steam and nuclear generation each can provide dispatchable, base load power while also maintaining or increasing fuel diversity. 280 Utilities may be willing to pay a premium for these generation sources because they could serve as a hedge against the possibility that future natural gas prices will far exceed projected levels. Accordingly, the LCOE analysis demonstrates that the final standard’s costs are in line with power sources that provide analogous services

– dispatchable base load power and fuel diversity. We further note a number of conservative elements of the costs we used in making this comparison. In particular, these estimates include the highest value in the projected range of potential costs for partial CCS . They do not reflect revenues which can be generated by selling captured CO 2 for enhanced oil

280 As another example, San Antonio customers will benefit from low- carbon power from the Texas Clean Energy Project. CPS Energy CEO Doyle Deneby said in a news release: “ Adding clean coal to our portfolio dovetails with our strategy to diversify and reduce the carbon intensity of the power we supply to our customers .” www.bizjournals.com/sanantonio/news/2014/10/06/cps
energy- strikes
- new- deal - to -buy-power - from.html***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **273** of **763** recovery, and reflect the costs of partial CCS rather than potentially less expensive alternative compliance paths such as
a utility boiler co - firing with natural gas. See also V.H.7 and 8 below. 6. Comparison with Monetized Benefits In assessing the final standard’s costs, we also took into account a comparison of the marginal costs of applying the standard to an individual facility with the associated marginal benefits. Again, this comparison supported our conclusion that the costs are reasonable. As discussed above in section V.H.3 , our modeling analysis indicated that , under a wide range of scenarios, including unlikely natural gas prices and other particularly favorable cost assumptions, construction of new fossil steam generation is uneconomical in the near
- future. Although our modeling did not identify any situations where new fossil steam units were economical to construct

— even in the absence of this rule, over the wide range of possible futures analyzed

— public comments and public information suggested that developers may consider constructing a limited number of new fossil steam EGUs in the coming years. In assessing the impact of this rule, the EPA accordingly conducted an illustrative analysis to identify and consider the costs and benefits that would be associated with adding partial***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **274** of **763** CCS to an individual gene ric fossil steam unit. In our “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” ( EPA452/R
- 15
- 005, August 2015 ) (RIA) , Chapter 5, we found that the quantifiab le health and climate benefits would exceed the regulatory costs under a range of assumptions . This analysis again supports our conclusion that the costs of the standard are reasonable . Our conclusion is further bolstered by conservative aspects of our benefit estimates. The SC - CO 2 estimates applied in our analysis do not capture all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature, as discussed in detail in the RIA . In particular, the Intergovernmental Panel on Climate Change (IPCC) Fourth Assessment Report (2007 ) concluded that “it is very likely that [ SC - CO 2 estimates ] underestimate the damage costs . ” 281 Furthermore, the monetized non
- GHG benefits do not capture a number of other important benefits associated with reductions in criteria and hazardous air pollutants.

281 Since then, the peer - reviewed literature has continued to support this c onclusion. For example, the IPCC Fifth Assessment Report observed that SCC estimate s continue to omit various impacts that would likely increase damages.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **275** of **763** In addition, our cost estimates were developed based on middle of the road assumptions regarding the costs of constructing and operating a new fossil steam generation unit . We also are not estimating any revenue generated from sale of captured CO 2 for use in EOR operations, a conservative assumption. We anticipate that if a firm found it desirable to construct a new fossil steam unit in the future under this standard, it would be under circumstances where the economic conditions for the unit are particularly favorable, for example, in locations where EOR is available and/or the costs of operation are lower. Accordingly, this comparison supports our conclusion that the cost o f the final standard is reasonable. 7. Overall Costs and Economic Impacts As noted above, an assessment of national costs is also an appropriate means of evaluating the reasonableness of costs under CAA section 111. See Sierra Club , 657 F.2d at 330. The EPA considered the regulation’s overall costs and economic impacts as part of its RIA. The RIA demonstrates that these costs would be negligible and that the effects on electricity rates and other market indicators would similarly be minimal. These result s are driven by the existing market context for fossil
- steam generation. Even in the absence of the standards of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **276** of **763** performance for newly constructed EGUs, substantial new construction of uncontrolled fossil steam units is not anticipated under existing preva iling and anticipated future economic conditions. Modeling projection s from government, industry, and academia anticipate that few new fossil steam EGUs will be constructed over the coming decade and that those that are built would have CCS. 282 Instead, EIA data shows that natural gas is likely to be the most widely
- used fossil fuel for new construction of electric generating capacity in the near future . 283 Of the coal - fired units moving forward at various advanced stages of construction and development
- Southern 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 p rimary reasons for this rate of current and projected future development of new coal projects include highly competitive natural gas prices, lower electricity demand, 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 market trends.
282 RIA chapter 4. For example, even in the EIA’s sensitivity analysis that assumes higher natural gas prices and electricity demand, the EIA does not project any additional coal 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 assume GHGs emission limitations. AEO 2015 283 Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 2015.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **277** of **763** Because of the expectation of no new fossil steam generation, the RIA projects that this final rule will result in negligible costs overall on owners and operators of newly cons tructed EGUs by 2022. 284 More broadly, this regulation is not expected to have significant effects on fuel markets, electricity prices, or the economy as a whole, as described in detail in Chapter 4 of the RIA. In comparison, courts have upheld past regulati ons that imposed substantial overall costs in order to protect 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]onsumers will ultimately bear these costs, both directly in the form of residential utility bills, and indirectly in the form of higher consumer prices due to increased energy costs, ” before concluding that the costs were reasonable. Id.

284 Conditions in the analysis year of 2022 are represented by a model year of 2020.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **278** of **763** The projected total incremental capital costs associated with the standard we are finalizing today are dramatically lower than was the case for this prior standard, as well as other prior standards s ummarized 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 projected incremental cost of tens of billions of dollars. 285 Here, by contrast, few if any fossil steam EGUs are projected to be built in the foreseeable future, indicating that the total incremental costs are likely to be considerably more modest. Commenters stated that the cost provision in CAA section 111(a)(1 ) does not authorize the EPA to consider the 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 reasons of its cost to individual sources . At the same time, total projected costs are relevant in assessing the overall reasonableness of costs associated with a standard. Our analysis demonstrates that the impacts on the industry as a whole are negligible, and are certainly not greater than “what the industry could bear and

285 Sierra Club , 657 F . 2d at 314 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **279** of **763** survive.” 286 These facts support EPA’s overall conclusion that the costs of the standard are reasonable. 8 . Opportunities to Further Reduce Compliance Costs While the EPA believes , as detailed above, that there is sufficient evidence to show that the final standards of performance for new steam generating units can be met at a reasonable cost, we also note that there are potentia l opportunities to further reduce compliance costs . We believe that, in most cases, the actual costs will be less than those presented earlier . As explained in more detail in the following subsection , a new utility boiler can meet the final standard of performance by
co - firing with natural gas. Some project developers may choose to utilize natural gas co
- firing as a means of delaying, rather than avoiding, implementation of partial CCS. Developers can also choose to install IGCC with a small amount of natural gas
co - firing at costs within the range of SCPC with partial CCS, although slightly higher. The EPA also notes that new units that capture CO 2 will likely be built in areas where there are opportunities to sell the captured CO 2 for some useful purpose prior to (or concomitant with) permanent storage. The DOE refers to this as “carbon

286 Portland Cement Ass’n , 513 F. 2d at 508.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **280** of **763** capture, utilization and storage” or CCUS. In particular, the ability to sell captured CO 2 for use in enhanced oil recovery operations offers the most opportunity to reduce costs. In this regard, the newly- operating Boundary Dam facility is 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 state governments. The need for subsidies to support emerging 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 government subsidy such as tax benefits, loan guarantees, low
- cost leases, or direct expenditures for some aspect of development and utilization, ranging from exploration to control installation. This is true for fossil fuel
- fired , as well as nuclear - , geothermal - , wind
- , and solar - generated electricity . As stated earlier, the EPA considers the costs of partial CCS at a level to meet the final standard of performance to be reasonable even without consider ing these opportunities to

287 The EPA is referring to the Kemper facility here as an example of how costs can be defrayed, not for use of 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
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– Do Not Cite, Quote or Release During Review *** Page **281** of **763** 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 CO2 /MWh - g is the BSER for newly constructed fossil fuel - fired steam generating EGUs, we also note that operators can consider the use of natural gas co
- firing to achieve the final emission 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 approximately 40 percent (heat input basis) and could potentially avoid (or delay) installation and use of partial CCS altogether . Natural gas co - firing has long been recognized as an option for coal - fired boilers to reduce emissions of criteria and hazardous air pollutants. EPRI sponsored a study t o assess both technical and economic issues associated with natural gas co
-***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **282** of **763** firing in coal
- fired boilers . 288 They determined that the largest number of applications and the longest experience time is with natural gas reburning and with supplemental gas firing . Natural gas reburning has been used primarily as a NOX control technology. It is implemented by introducing natural gas (up to 20 percent total fuel heat input) in a secondary combustion zone (called the “reburn zone”) downstream of the primary combustion zone in the boiler. Injecting the natural gas creates a fuel rich zone where NOX formed in the main combustion zone is reduced to nitrogen and water vapor. Higher levels of natural gas co
- firing can be met by utilizing supplemental gas co
- firing (either alone or along with natural gas reburning). This involves the simultaneous firing of natural gas and pulverized coal in a boiler’s primary combustion zone. Others have also evaluated configurations that would allow coal - fired units to utilize natural gas. 289 , 290

288 Gas Cof iring Assessment for Coal Fired Utility Boilers; Final Report, August 2000; EPRI Technical Report available at www.epri.com. 289 Many of the studies evaluated opportunities to use natural gas reburn, natural gas co - firing and other configurations in existing coal
- fired boilers. Those conclusions would 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 Internationa l Technical Conference on Clean Coal and Fuel Systems June 2012 Clearwater, FL, available at http://www.babcockpower.com/pdf/RPI
- TP - 0228.pdf .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **283** of **763** A 2013 article entitled “Utility Options for Leveraging 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 four most practical options are co
- firing coal and gas in the same boiler, converting the coal
- fired boiler to gas - only operation, repowering the coal plant with natural gas

– fired combustion turbines, or replacing the coal plant with a combined cycle plant. [...] Co
firing is the lowest
- risk option for substituting gas use for coal. The EPA examined compliance costs for a new steam generating unit to meet the final standard of performance using natural gas co - firing and compared those costs to the estimated costs of meeting the final standards using partial CCS. Those costs are provided below in Table 9. **Table 9**  **. Predicted Costs to Meet the Final Standard Using Natural Gas Co** **- firing.**  **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

291 Utility Options for Leveraging Natural Gas , 10/01/2013 article in Power . Available at http://www.powermag.com/utility
options
- for - leveraging
- natural - gas/ 292 Costs and emissions for non
- natural gas co - fired cases are from “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal
- Fired Power Pl ants”, DOE/NETL
- 2015/1720 (June 2015). Costs and emissions for natural gas co - fired cases are EPA estimates.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **284** of **763** 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 assume 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 overestimating actual compliance costs since there exist other less expensive means of meeting the promulgated standa rd. 293 Notwithstanding that costs for a SCPC to meet the standard would be lower if it co
- fired with natural gas , we have not identified that compliance alternative as BSER because we believe that new coal
- fired steam electric generating capacity would be built to provide fuel diversity, and burning substantial amounts of natural gas would be contrary to that object ive. In addition, this choice would not promote use of advanced pollution control technology. New IGCC has costs which are comparable to SCPC , as does IGCC with natural gas co
-

293 Certain commenters argued that the proposed standard essentially mandated a sole method of compliance, and hence const ituted a work practice for purposes of section 111(h ) of the Act. These commenters argued further that the EPA had failed to justify the proposal under the section 111(h) criteria. The EPA disagrees with the premise of these comments, but, in any case, there are clearly multiple compliance paths available for achieving the final standard.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **285** of **763** firing, 294 but we are choosing not to identify it as BSER for reasons stated at section s V.C.2 and V.P : use of IGCC does not advance emission control beyond current levels of performance for sources which may choose to utilize IGCC technology . Nonetheless, use of IGCC remains a viable , demonstrated compliance option to meet the 1,400 lb CO 2 /MWh
- g standard of performance, and is available at reasonable cost and (as shown at section V.P below) without significant adverse nonair quality impacts or energy implications. b. Costs are reasonably expected to decrease over time . The E PA reasonably expects that the costs of CCS will decrease over time
as the technology becomes more widely deployed . Although, for the reasons that have been noted , we consider the current costs of CCS to be reasonable, the projected decrease in those costs further supports their reasonableness. The D.C. Circuit case law that authorizes determining the “best ” available technology on the basis o f reasonable future projections support s taking into account projected cost reductions as a way to suppo rt the reasonableness of the costs. We expect the costs of CCS technologies to decrease for several reasons. We expect that significant additional knowledge
294 IGCC units already have combined cycle capacity, and so can be readily operated in whole or in part using natural gas as a fuel. Indeed, both the Edwardsport and Kemper IGCC facilities have operat ed at times by firing exclusively natural gas .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **286** of **763** will be gained from deployment and operation of the new coal
fired generation facilities that are e ither operating or are nearing completion. These would include the Boundary 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 CC S units 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 provides SaskPower the opportunity to share the knowledge and experience from the Boundary Dam Unit #3 facility with global energy leaders, technology developers, and project developers. SaskPower, in partnership with Mitsubishi and Hitachi, is also helping to advance CCS knowledge and technology development through the creation of the Shand Carbon Capture Test Facility

295 “Boundary Dam

– The Future is Here”, plenary presentation 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
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– Do Not Cite, Quote or Release During Review *** Page **287** of **763** (CCTF). 297 The test facility will provide technology developers 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 Carbon Capture Center (NCCC). The NCCC

– located at Southern Company’s Plant Gaston in Wilsonville, AL

– provides first
- class facilities to test new capture technologies for extended periods under commercially representative conditions with coal
- derived flue gas and syngas. 298 We expect continued additional cost reductions to come from knowledge gained from continued operation of non -power sector industrial projects which, as we have discussed, are informative in transferring the technology to power sector applications. We expect the on - going research and development efforts

– 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 pollution control technologies as a result of learning
-by- doing, reductions in financial premiums related to risk, research and

297 www.saskpowerccs.com/ccs
-projects/shand
- carbon - capture - test facility/ 298 www.nationalcarboncapturecenter.com/index.html***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **288** of **763** development investments, and other factors have been ob served over the decades.
c. Opportunities to reduce cost through sales of captured 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 pro duction in order to increase oil production efficiency. CO 2 -EOR has been successfully used for decades at many production fields throughout the U.S. to increase oil recovery. The use of CO 2 for EOR can significantly lower the net cost of implementing 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 projects under construction or at an advanced stage of planning, 70 percent intend to use captured CO 2 to improve recovery of oil in mature fields. 299 See also section V.M.2 below. I. Key Comments Regarding EPA’s Consideration of Costs In its consideration of the costs associated with the final standard, the EPA considered a range of different cost metrics, each with its individual strengths and weaknesses. As discussed

299 Tracking Clean Energy Progress 2013, International Energy Agency (IEA), Input to the C lean Energy Ministerial, OECD/IEA 2013.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **289** of **763** above, each metric supports the EPA’s conclusion that the costs of the final standard are reasonable. In this section, we review the comments received on assessing cost reasonableness and specific cost metrics. We explain how these comments informed our consideration of different metrics and cost reasonableness in general. 1. Use of LCOE as a Cost Metric As noted, CAA section 111(a) directs the EPA to consider “cost” in determining if the BSER is adequately demonstrated. It does not provide further guidance as to how costs are to be considered, thus affording the EPA considerable discretion to choose a reasonable means of cost consideration. See, e.g. Lignite Energy Council v. EPA, 198 F. 3d at 933. Certain commenters nonetheless argued that LCOE was an impermissible metric because it does not measure the cost of achieving the emission reduction, but rather measures the impact on the product produced by the entity subject to the standard. 300 The EPA does not agree that its authority is so limited . I ndeed, in the first decided case under section 111, the D.C. Circuit, in holding that the EPA’s consideration of costs was reasonable, specifically noted the EPA’s examination of the impact of the standards on the regulated source category’s product in

300 Comment s of EEI, pp 94
- 5.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **290** of **763** comparison to competitive products. Portland Cement Ass’n v. EPA, 486 F. 2d at 388 (“costs of control equipment could be passed on without substantially affecting competition with construction substitutes such as steel, asphalt, and aluminum”). Commenters also argued that the choice of LCOE as a cost metric masked consideration of the considerable capital costs associated with CCS. The EPA disagrees with this contention. 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 electricity services and align on dimensions other than just cost , then the LCOE provides a useful comparison of which technolo gies are least cost. The EPA certainly does not minimize that project developers must take capital costs into consideration, and as discussed in section V.H.4 above, the EPA accordingly has considered direct capital costs here as part of its assessment and found those costs to be reasonable. In addition, the EPA notes that its comparison of the marginal impacts from an individual illustrative facility’s compliance with the standard, discu ssed in detail above and in the RIA Chapter 5 , took into account the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **291** of **763** marginal capital costs that would be incurred by an individual facility. At the same time, the agency believes LCOE is a valuable complementary metric because there are other costs that are also considered when evaluating technology options to provide new generating capacity. According to EIA301 , the capital costs represent roughly 63 percent of the LCOE for a new coal
- fired SCPC plant; roughly 66 percent of the LCOE for a new IGCC plant; roughly 74 percent of the LCOE for a new nuclear plant; and only about 22 percent of the LCOE for a new NGCC unit. The LCOE of a new NGCC unit is much more strongly affected by fuel costs (natural gas). As we have discussed in de tail in this preamble, in the preamble for the January 2014 proposal, and in associated technical support documents, for a variety of reasons, the power sector has moved toward increased use of natural gas. If capital was the only cost that utilities and p roject developers considered, then they would almost certainly always choose to build a new NGCC unit. However, the EPA recognizes the variety of factors that can be involved in selecting a generation source beyond capital costs, and in considering cost reasonableness we accordingly also considered metrics that encompassed other costs as well as the value of fuel and f leet diversity.

301 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **292** of **763** 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 comparison is app ropriate and valid because , as discussed at V.H.3 above, under current and foreseeable economic conditions affecting the cost of new fossil steam generation and new nuclear generation relative to the cost of new natural gas generation, both new nuclear power and fossil steam generation are similarly not competitive with new natural gas if evaluated on the basis of LCOE alone. Nonetheless, both are important potential alternatives to natural gas power for those interested in dispatchable base load power that maintains or increases fuel diversity. As shown in a survey of recent IRP filings in the docket 302 and section II.C.5 above , several utilities are considering new nuclear power as a potential generation option. Because both fossil steam and nuclear generation serve a comparable role of offering a diverse source of base load power generation, the EPA concludes that the comparison of their LCOE is a valid approach to evaluating cost reasonableness. 2. Use of Cost E stimates from DOE/NETL and DOE/EIA

302 Technical Support Document
- “Review of Electric Utility Integrated Resource Plans” (May 2015), available in the rulemaking docket EPA- HQ - OAR- 2013
- 0495.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **293** of **763** In the January 2014 proposal, the EPA relied mostly on the cost projections for new fossil fuel
- fired generating sources that were informed by cost studies conducted by DOE/NETL. The EPA relied on the EIA’s AEO 2013 projections for non
- fossil based generating sources (i.e., nuclear, renewables, etc.). For this final rule, the EPA continues to rely most heavily on DOE/NETL cost projections for fossil fuel generating technologies and on the updated DOE/EIA AEO 2 014 for nuclear and other base load non - fossil generation technologies.
a. DOE/NETL cost and performance studies . The DOE/NETL “Cost and Performance Baselines for Fossil Energy Plants” are a series of studies conducted by NETL to establish estimates for the c ost and performance of combustion and gasification based power plants with and without CO 2 capture and storage. 303 The studies evaluate numerous technology configurations utilizing different coal ranks and natural gas. The EPA relied on those sources becaus e the NETL studies are the most comprehensive and transparent of the available cost studies and NETL has a reputation in the power sector industry for producing high quality, reliable work. 304 The NETL studies

303 http://www.netl.do e.gov/research/energy
- analysis/energy
baseline
- studi es 304 The NETL costs and studies are often cited in academic and other publications.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **294** of **763**
were extensively peer reviewed. 305 The EPA Science Advisory Board Work Group considering the adequacy of the peer review noted EPA staff’s statement that “the NETL studies were all peer reviewed under DOE peer review protocols”, further noted EPA staff’s statement that “the different level s of review of these DOE documents met the requirements to support the analyses as defined by the EPA Peer Review Handbook,” and concluded that “peer review on the DOE documents” was conducted “at a level required by agency guidance.” 306 The cost estimates were indicated by DOE/NETL to carry an accuracy of - 15 percent to +30 percent on the capital costs , consistent with a AACE Class 4 cost estimate

– i.e . , a “feasibility study” level of design engineering. 307 The DOE/NETL

305 The initial NETL study “Cost and Performance Baseline for Fossil Energy Plants, Vol. 1: Bituminous Coal and Natural Gas to Electricity” (2006) was subject to peer review by industry experts, academia, and government research and regulatory agencies. Subsequent iterations of the study were not 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 Underlying Science to Members of the Chartered SAB and SAB Liaisons ( page 3, Jan. 24, 2014). http://yosemite.epa.gov/sab/sabproduct.nsf/F43D89070E89893485257 C5A007AF573/$File/SAB+work+grp+memo+w+attach+20140107.pdf. The SAB’s statement that these guidance documents “require” any specific peer review is an overstatement, since guidance documents, by definition, do not mandate any specific course of action. 307 Recommended Practice 18R
- 97 of the Association for the Advancement of Cost Engineering International (AACE) describes a***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **295** of **763** further notes that “The value of the study lies not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluate d. ” 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 the post combustion capture technology

– the Shell Cansolv amine
-based process – that is being utilized at the Boundary Dam Unit #3 facility. 309 The EPA used this latest version of the NETL studies not only to assure that it considers the most up
- to - date information but also to address public comments criticizing the proposal for relying on out
- of - date cost information. b. Other studies that corroborate NETL cost estimates . A variety of government, industry and academic groups routinely conduct studies to estimate costs of new generating technologies. These studies use techno
- economic models to predict the cost to build a new generating facility at some point in the future. These Cost Estimate Classification System as applied in Engineering , Procurement and Construction for the process industries . 308 “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity ” Rev 2a (Sept 2013); DOE/NETL
- 2010/1397, page 9. 309 Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3, Ju ly 6, 2015, DOE/NETL
- 2015/1723.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **296** of **763** studies often use levelized cost of electricity (LCOE) to summarize costs and to compare the competiveness of the different generating technologies. A variety of groups have recently published LCOE estimates for new dispatchable generating technologies. Those are shown below in Table 10 . The table shows LCOE projections from the EPA’s January 2014 propos al, from studies conducted by the Electric Power Research Institute (EPRI) 310 , by the DOE’s Energy Information Administration (EIA) in their 2015 Annual Energy Outlook ( AEO 2015 ), by the DOE’s National Energy Technology Laboratory (NETL), and by researchers from the Department of Engineering and Public Policy at the Carnegie Mellon University (CMU) in Pittsburgh, PA. 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 compares the predicted LCOEs of those technologies. Importantly, the analysis presented in the report uses cost and performance data from several recent studies, and applies a common methodology and economic parameters to derive comparable lifetime costs.

310 EPRI is a non
-profit organization, headquartered in Palo Alto, CA, that conducts research on issues related to the U.S. electric power industry (www.epri.com) . 311 www.globalccsinstitute.com***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **297** of **763** Analysis and findings in the paper reflect costs specific to the U.S. The fact that these various groups have conducted independent studies and that the results of those independent studies are reasonably consistent with the estimates of DOE/NETL are further indications that the DOE/NETL cost estimates are
reas onable.*** EO 12866 Review
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– Do Not Cite, Quote or Release During Review *** **Table 10**  **. Selection of Levelized**  **Cost of Electricity (LCOE) Projections New Generation**  **Lazard 312**  **EPRI 313**  **AEO2015 314**  **DOE/NETL 315**  **CMU 316**  **GCCSI 317**  ****** **Technology $2014/MWh**  **$2011/MWh $2013/MWh** ***** **$2011/MWh******* **$2010/MWh $2014/MWh**  SCPC

– no CCS 66 62

– 77 95 76

– 95 59 78 SCPC - full CCS 151 102

– 137
- 140

– 176
- 115
- 160 SCPC - 16% CCS - - - 92
- 117
- - Nuclear *** 92

– 132 85

– 97 87

– 115
- - 86
- 102 Biomass 87

– 116 90

– 155 94

– 113
- - 123
- 137 IGCC 102 82

– 96 116 94

– 120
- - IGCC - full CCS 171 105

– 136 144 142

– 178
- - NGCC 61
- 87 33

– 65 73 58 63 60 * EIA, in cost projections for SCPC and IGCC with no CCS, include s a climate uncertainty adder (CUA ), which is a 3
-percentage point increase in the cost of capital . In contrast,
312 Lazard’s Levelized Cost of Energy Analysis

– Version 8.0 (Sept 2014); available at http://www.lazard.com/media/1777/levelized_cost_of_energy_
-_version_80.pdf and in the rulemaking 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 New Generation Resources in the Annual Energy Outlook 201 5 ”, Available at: www.eia.gov/forecasts/aeo/electricity_generation.cfm ; the LCOE values displayed incorporate
- 10%/+30% for uncertainty for biomass and nuclear. 315 “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal
- Fired Power Plants” DOE/NETL
- 2015/1720 (June 22, 2015). 316 CMU is Carnegie Mellon University; Zhai, H., Rubin, E.; “Comparative Performance and Cost Assessments of Coal - and Natural Gas - Fired Power Plants under a CO 2 Emission Performance Standard Regulation”, Energy & Fuels , 2 013, 27, 4290, Table 1 . 317 “ The Costs of CCS and other Low- Carbon Technologies
- 2015 update ” July 2015, Global CCS Institute, Available at: http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs
- ccs other - low- carbon - technologies
- 2015
- update.pdf***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **299** of **763** DOE/NETL utilized conventional financing for cases without CCS and utilized high
- risk financial assumptions for cases that include CCS. ** The Global CCS Institute provided range for coal with full CCS (shown as “CCS(coal)” in Figure 5.2 of the referenced report) reflects a combination of costs for both PC and IGCC coal plants. ** * EIA AEO assumes use of Westinghouse AP1000 technology. Other groups assume a wider range of technology options.*** EO 12866 Review
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– Do Not Cite, Quote or Release During Review *** The LCOE values from the Lazard, EPRI, and NETL studies are presented as a range. The EPRI costs incorporate uncertainty reflecting the range of inputs (i.e., capital costs, fuel costs, fixed and variable O&M, etc.). The NETL costs are indicated to carry an accuracy of - 15 percent to + 30 percent, consistent with a “feasibility study” level of design. The range in Table 10 is the NETL projected costs with the
- 15 percent to +30 percent uncertainty on the capi tal costs . Overall , as can be seen from the results in Table 10 , the range of LCOE estimates from the different groups are in reasonable agreement with the DOE/NETL estimates most often representing the most conservative of the estimates shown . The EIA co st estimates include a climate uncertainty adder (CUA)

– represented by a three percent increase to the weighted average cost of capital

— to certain coal
- fired capacity types. The EIA developed the CUA to address inconsistencies between power sector model ing 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 typically assigned by project developers and utilities to GHG
- intensive projects in a context of climate uncertainty. The EPA believes the CUA is consistent with the industry’s planning and evaluation framework (demonstrable through IRPs and PUC orders) and is therefore pertinent when evaluating the cost competitiveness of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **301** of **763** alternative generating technologies. The EPA believes the CUA is relevant in considering the range of costs that power companies are willing to pay for generation alternatives to natural gas . c. Industry information that corroborates NETL cost estimates . Information from vendors of CCS technology also supports the reliability of the cost estimates EPA is using here. 318 Specifically, the EPA had conversations with representatives from Summit Carbon Capture, LLC regarding available cost information. Cost estimates provided by another leading provider of CCS technology likewise are consistent (indeed, somewhat less than) the estimates EPA is using for purposes of cost analysis in the rule. Summit Carbon Capture’s primary business is large
- scale carbon capture from power and other industrial projects 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 manufacturers for fossil fuel power production equipment. Their current projects include the 400 MW IGCC Texas Clean Energy Project and the Caledonia Clean Energy Project

– a new project underway in the

318 See section V.F above, explaining that the D.C. Circuit has repeatedly stated that vendor statements are probative in demons trating that a technology is adequately demonstrated under section 111. 319 http://www.summitpower.com/proje cts/carbon
- capture/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **302** of **763** United Kingdom

– and a variety of other projects under development which are not yet pub lic. Summit is also interested in potentially retrofitting CCS onto existing coal
- fired plants for the purpose of capturing CO 2 for sale to EOR markets. Summit provided the EPA with copies of slides from a presentation that it has used in different public forums. 320 The presentation focused on costs to retrofit available carbon capture equipment at an existing PC power plant that is ideally located to take advantage of opportunities to sell captured CO 2 for use in EOR operations. Summit received proprietary c osting information from numerous technology providers and that information, along with other publically available information, was used to develop their cost predictions. 321 Though the primary focus of their effort was to examine costs associated with retrof itting CCS to an existing coal fired power plant, Summit Power also calculated costs for several new generation scenarios

– including the cost of a new NGCC, a new SCPC, a new SCPC with full CCS, and a new 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, remarks by Jeffrey Brown (amended to address EPA questions on the original). Available in the rulemaking docket . 321 No proprietary or business confidential information was shared with EPA. No specific vendors were mentioned by name during discussions with Summit Power. Summit also used available DOE/NETL and EIA cost information.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **303** of **763** 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 ... ex isting coal plants retrofitted with available CCS equipment can be cost competitive with development of new NGCC generation.” 322 In June 2012, Alstom Power released a report entitled “Cost assessment of fossil power plants equipped with CCS under typical scenarios”. 323 , The study examined costs for a new coal
fired 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 from Summit

– are shown in Table 11 below. The DOE/NETL estimated costs are also included for comparison. The results show predicted costs for a new SCPC ranging from $53/MWh to $8 2 /MWh and costs to implement full CCS ranging from $97/MWh to $14 3 /MWh. Costs to
322 Others have come to similar conclusions

– that retrofit of CCS technology at existing coal
- fired power plants can be feasible

– e.g., “The results indicate that for about 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 characteristics and fuel pr ices.” (Zhai, H.; Ou, Y.; Rubin, E.S.; “Opportunities for Decarbonizing Existing U.S. Coal
- fired Plants via CO 2 Capture, Utilization, and Storage”, accepted for publication in Env. Sci & Tech. (2015). 323 Leandri, J., Skea, A., Bohtz, C., Heinz, G.; “Cost as sessment of fossil power plants equipped with CCS under typical scenarios”, Alstom Power, June 2012. Available in the rulemaking docket: EPA- HQ - OAR- 2013
- 0495.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **304** of **763** implement varying levels of partial CCS are also provided for comparison. The industry cost estimates are on the lower end of the range of costs predicted from other techno - ec onomic studies (see Table 11 below ) and, like those economic studies, are affected by the specific assumptions. As with the techo
- economic studies presented earlier in Table, there is relatively good agreement among these projected costs and the DOE/NETL costs. There is relatively good agreement in the incremental levelized cost to implement full CCS on the new SCPC units (ranging from 74 to 85 percent) and to implement 50 percent CCS on the new SCPC unit (from 41 to 45 percent increase) . These industry estimates are also lower than the DOE/NETL estimates for both full and 50 percent partial CCS (with the incremental cost percentage for full CCS being almost identical ), providing further support for the reasonableness of the EPA using the NETL cost estimates here. **Table 11**  **. Industry LCOE Estimates for Implementation of Post****** **Combustion CCS** 324
324 Note that in other tables in this preamble, the EPA has presented LCOE values from the DOE/NETL work as a range in order to incorporate the uncertainty on the capital costs. The range is not present here for easy comparison with the industry 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 A
3 in “ 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.***EO 12866_Review
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Summit Alstom DOE/NETL $/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 5 2 .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 EPA using NETL information. Assumed natural gas prices = Summit ($4/mmBtu); Astom ($3.9/mmBtu); EPA ($ 5.00 /mmBtu ). The EPA notes that in its public comments, Alstom maintained that “no CCS projects that would [sic] be considered cost competitive in today’s energy economy.” 325 As explained above, no steam electric EGU would be cost competitive even without CCS

– and that is substantiated in the projected costs present ed above in Table 11 where NGCC is consistently 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 deterrent for capacity that would otherwise be constructed. More important,
325 Alstom Comment p. 3. The comment also urged EPA to evaluate costs without considering EOR opportunities (which in fact is our methodology, albeit a conservative one), and without considering possible subsidies. Id. The LCOE and capital cost estimates above are direct cost comparisons, again consistent with the commenter’s position.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **306** of **763** Alstom does not challenge the specific cost estimates used by the EPA at proposal (and in this final rule), nor disavow its own estimates of CCS costs (which are even less) which it is publically disseminating in the marketpla ce. See also section V.F. 3 above, quoting Alstom’s press release stating unequivocally that “CCS works and is cost
- effective”. The EPA reasonably is relying on the specific Alstom estimates which it is using for its own commercial purposes, and not on the generalized concerns presented in its public comments. d. Use of cost information from EIA Annual Energy Outlook (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 energy supply, demand, and prices focused on U.S. energy markets. The predictions are based on results from EIA’s National Energy Modeling System (NEMS). The AEO costs are updated annually, they are highly scrutinized, and they are widely used by those involved in the energy sector . In the January 2014 proposal, the EPA presented LCOE costs for new non - fossil dispatchable generation (see 77 FR 1477, Table 7) from the AEO 2013 . Those costs were updated as part of the AEO 2015 release. The estimated cost for all of these technologies decreased from AEO 2013 to AEO 2014 and AEO 2015 . This was due to changes in the interest rate s that resulted in***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **307** of **763** lower financing costs relative to those used the AEO 2013 . 326 The EIA commissioned a comprehensive update of its capital cost assumptions for all generation technologies in 2013. Fuel cost and financial assumptions are updated for e ach edition of the Annual Energy Outlook.
e. Accounting for uncertainty of projected costs . As previously mentioned, the projected costs are dependent 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 incorporation of any incentives such as tax credits or favorable financing that may be available to the project developer. There are also regional or geographic differences that affect the final cost of a project. The LCOE projections in this final action are not intended to provide an absolute cost for a new project using any of these respective technologies. Large construction projects

– as these would be

– would be subjected to detailed cost analyses that would take into consideration site
- specific information and specific design de tails in order to determine the project costs. The DOE/NETL noted that the cost estimates from their studies carry an accuracy in the range of
- 15 percent to +30 percent, which is consistent with a “feasibility study” level of

326 www.eia.gov/o iaf/beck_plantcosts/pdf/updatedplantcosts.pdf.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **308** of **763** design. They also noted that the value of the studies lies “not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated.” The EIA AEO 2015 presented LCOE costs as a single point estimate representing average nationwide costs and separately as a range to represent the regional variation in costs. In order to compare the fossil fuel generation technologies from the NETL studies with the cost projections for non
- fossil dispatchable 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, nuclear expert s from EIA staff have indicated to the EPA that a range of uncertainty of
- 10 percent to +30 percent on the capital component of the LCOE can be expected based on market uncertainties. Specifically, these staff experts expect that

327 EIA does not provided uncertainty estimates in the AEO cost projections. However, EIA staff have indicated to EPA that a range of uncertainty of
- 10%/+30% on the capital component of the LCOE can be expected based on market uncertainties. [expand and docket email and cite to it] .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **309** of **763** nuclear plants currently under construction would not have
capital costs under estimates and that one could expect to see a 30 percent “upside” variation in capital cost. There is also insufficient market data to get a good statistical range of potential capital cost variation (i.e. , only two plants under construct ion, neither complete). This is reasonably consistent with estimates for nuclear costs estimated by Lazard (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. 3. Use of Costs from Current P rojects Although we are relying on cost estimates drawn from techno - economic models, we recognize that there are a few s team electric plants that include CCS that have been built, or are being constructed. Some information about the costs (or cost - to date) for these projects is known. We discuss in this section the costs at facilities which have installed or are installing CCS, why the EPA does not consider those costs to be reasonably predictive of the costs of the next new plants to be built , and***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **310** of **763** why the EPA considers that the next new plants will have lower
costs along the lines predicted by NETL. 328 The Boundary Dam Unit #3 facility utilizing post
- combustion capture from Shell Cansolv is now operational. Petra Nova, a joint venture between NRG and JX Nippon Oil & Gas Exploration, is currently constructing a pos t - combustion capture system at NRG’s WA Parish generating station near Houston, TX. The post
combustion capture system will utilize MHI amine
-based solvents and is currently being constructed with plans to initiate operation in 2016. 329 Construction on Miss issippi Power’s Kemper County Energy Center IGCC facility is now nearly complete. The combined cycle

328 The EPA notes that two of these facilities, Kemper and TCEP, received both assistan ce from DOE under EPAct05 and the IRC section 48A tax credit; and that the AEP Mountaineer pilot project received assistance from DOE under EPAct05. Under the most extreme interpretations of those provisions offered by commenters, the EPA would be preclude d from any consideration of any information from those sources , incl uding cost information, in showing whether a system of emission reduction is adequately demonstrated. We note, however, that many of these same commenters urged consideration of the cost information from these sources. In fact, the EPA is not relying on information about the costs of these sources to determine the BSER or the standards of performance in this rulemaking, and the EPA is discussing the cost information here to explain why not . Accordingly, this discussion of cost information from these s ources is not precluded by the EPAct05 and IRC section 48A provisions and, even if it is precluded, that would have no impact on the EPA’s determination of the BSER and the standards of performance in this rule. 329 http://www.nrg.com/susta inability/strategy/enhance
generation/carbon
- capture /wa
-parish
- ccs -project/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **311** of **763** portion of the facility has been generating power using natural gas. The gasification portion of the facility and the carbon capture system are undergoing system checks and training to enable commercial operations using a UOP SelexolTM pre
- combustion capture system in early 2016. 330 Another full - scale project , the Summit Power Texas Clean Energy Project has not commenced construction but remain s a viable project. Several other full
- scale projects have been proposed and have progressed through the early stages of design, but have been cancelled or postponed for a variety of reasons. Some cost information is also available for small demonstration pro jects

– including those that have been supported by USDOE research programs. These projects would include Alabama Power’s demonstration project at Plant Barry and the AEP/Alstom demonstration at Plant Mountaineer. Many commenters felt that the EPA should rely on those high costs when considering whether the costs are reasonable. The costs from these large - scale projects appear to be consistently higher than those projected by techno
- economic models. However, the costs from these full - scale projects repres ent first
- of - a kind (FOAK) costs and, it is reasonable to expect these costs to

330 http://www.mississippipower.com/about
- energy/plants/kemper
county- energy- facility/facts***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **312** of **763** come down to the level projected in the NETL and other techno economic 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 literature suggests that the per - unit cost of producing or using a given technology declines as experience with that technology increases over time, and this has certainly been the case with air pollution control technologies. Reductions in the cost of air pollution control technologies as a result of learning
-by- doing, research and development investments, and other factors have been observed over the decades. We expect that the costs of capture technology will follow this pattern. The NETL cost estimates reasonably account for this documented phenomenon. Specifically, “[I]n all cases, the report intends to represent the next commercial offering, and relies on vendor cost estimates for component technologies. It also applies process contingencies at the appropriate subsystem levels in an attempt to account for expected but undefined costs (a challenge for emerging technologies).” 331

331 “ Co st and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3 ”, DOE/NETL
- 2015/1723 (July 2015 ) at p. 38.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **313** of **763** Commenters argued that the next plants to be built would still reflect first
- of - a - kind costs, pointing to the newness of the technology and the lack of operating experience, i.e. the alleged absence of learning by doing. The EPA disagrees. In addition to operating experience from operating and partially constructed CCS projects, substantial research efforts are underway providing a further knowledge base to reduce CO 2 capture costs and to improve performance . The DOE/NETL sponsors an extensive research, development and demonstration program that is focused on developing advanced technology options that will dramatically lower the cost of capturing CO 2 from fossil fuel energy plants compared to currently available capture technologies. The large
- scale CO 2 capture demonstrations that are currently planned and in some cases underway, under DOE’s initiatives, as well as other domestic and international projects, will generate operational knowledge and enable continued commercialization and deployment of these technologies. Gas absorption processes using chemical solvents, such as amines, to separate CO 2 from other gases have been in use since the 1930s in the natural gas industry and to produce food and chemical grade CO 2 . The advancement of amine
based solvents is an example of technology development that has improved the cost and performance of CO 2 capture. Most single component amine systems are not practical in a flue gas***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **314** of **763** environment as the amine will rapidly degrade in the presence of oxygen and other contaminants. The Fluor Econamine FG process, the process modeled in the 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 construction. Other commercially available processes use sterically hindered amine formulations (for example, the Mitsubishi Heavy Industries KS

– 1 solvent) which are less susceptible to degradation and corrosion issues. The DOE/NETL and private industry are continuing to sponsor research on advanced solvents (including new classes of amines) to improve the CO 2 capture performance and reduce costs. As noted in section V.H.7.d above, SaskPower has created the CCS Global Consortium to facilitate further knowledge regarding, and use of , carbon capture technology . 332 This consortium provides SaskPower the opportunity to share its knowledge and experience with global energy leaders, technology developers, and project developers. SaskPower, in partnership with Mitsubishi and Hitachi, is also helping to advance CCS knowl edge and technology through the creation of the Shand

332 http://www.saskpowerccs.com/consortium/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **315** of **763** Carbon Capture Test Facility (CCTF). 333 The test facility will provide technology developers with an opportunity to test new and emerging carbon capture systems for controlling carbon emissions from coal
- fired power plants. We also note certain features of the commercial plants already built that suggest that their costs are uniquely high , and otherwise not fairly comparable to the costs of plants meeting the NSPS using the BSER . Most obviously, many of these projects involve deeper capture than the partial CCS that EPA assumes in this final action . In addition, cost overruns at the Kemper facility , mentioned repeatedly in the public comments, resulted in major part from highly idiosyncratic circumstances, and are related to the cost of the IGCC system, not to the cost of CCS. 334 The EPA does not believe that these unusual

333 http://www.saskpowerccs.com/ccs
-projects/ shand- carbon capture - test - facility/ 334 See Independent Monitor’s Prudency Evaluation Report for the Kemper County IGCC Project (prepared for Mississippi Public Utilities Staff), available at www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_C ONNECT&queue=CTS_ARCHIVEQ&docid=328417 (“Report”). As documented in this Report, costs escalated significantly because the developers adopted a “compressed schedule” in an attempt to obtain the IRC 48A tax credit, resulting in “engineering and design changes which are a normal result of detailed engineering and design ... occurring at the same time as, rather than ahead of, construction activities”, which did not allow for proper sequencing during construction. This “’just
- in
- time’ approach to engineering and procurement (meaning that the engineering was often completed shortly before material procurement and construction activities) resulted in a greater number of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **316** of **763** circumstances are a reasonable basis for assessing costs of either CCS or IGCC here . 4. Cost Competitiveness of New Coal Units As the EPA noted, all indications suggest that very few new coal - fired power plants will be constructed in the foreseeable future. Although a small number of new coal - fired power plants have been built recently, the industry generally is not building these ki nds of power plants at present and is not expected 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 current and projected natural gas prices. On average, the cost of generation from a new NGCC power plant is expected to be lower than the cost of generation from a new coal
- fired power plant , and the EPA has concluded that, even in the absence of the requirements of this final rule, very few new coal
- fired power plants will be built in the near term .

construction work
- arounds, conge stion of construction craft labor in the field, inefficiencies and additional steps that became necessary during construction to cope with this just
- in
time engineering, procurement and construction approach.” Report, p. 6. All senior management officials in charge of the project either resigned or were othe rwise replaced. Id. pp. 12, 16. Ironically, work was still completed too late to obtain the tax credit. Id. p. 15.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **317** of **763** Some commenters , however, disagreed with this conclusion . They contended instead that it is the CCS
-based NSPS that would preclude such new generation. However, as the EPA has discussed, there is considerable evidence that utilities and project developers are moving away

– or have already moved away

– from a long term dependence on coal - fired generating sources. A review of publicly available integrated resource plans show that many utilities are not considering construction of new coal
- fired sources without CCS. See S ection V. H.3 above. Few new coal fired generating sources have commenced construction in the past 5 years and, of the projects that are currently in the development phase, the EPA is only aware of projects that will include CCS in the design. As we have noted in this preamble, the bulk of new generation that has been added recently has been either natural gas
- fired or renewable sources. Overall, the EPA remains convinced that the energy sector modeling is reflecting the realities of the market in predicting very few new coal fired power plants in the near future

– even in the absence of these final standards. In addition, we note that the Administration’s CCS Task Force report recognized that CCS would not become more widely available without the advent of a regul atory framework that promoted CCS or provided a strong price signal for CO 2 . In this regard, we note American Electric Power’s statements regarding***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **318** of **763** the need for federal requirement for GHG control to aid in cost recovery for CCS projects, to attract othe r investment partners, and thereby promote advancement and deployment of CCS technology: “as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share”. 335 Indeed, AEP has stated that CCS is important for the very future of the industry: “AEP still believes the advancement of CCS is critical for the sustainability of coal
- fired generation.” 336 Today’s action is an important component in developing that needed regulatory framework 5. Accuracy of Cost Estimates for T ransportation and Geologic Sequestrati on The EPA’s estimates of costs take into account the transport of CO 2 and sequestration of captured CO 2 . E stimates of

335 www/aep.com/newsroom/newsrelea ses/?id=1704. 336 “ CCS LESSONS LEARNED REPORT American Electric Power Mountaineer CCS II Project Phase 1 ” , p repared for The Global CCS Institute Project # PRO 004, January 23, 2012, page 2. Available at: www.globalccsinstitute.com/publications/ccs
- lessons - learnedreport - american
- electric
-power -mountaineer
- ccs - ii
-project
-phase 1 ; See also AE P FEED Study at pp. 4, 63, Available at: www.globalccsinstitute.com/publications/aep
-mountaineer
- ii
project
- front - end- engineering
- and- design
- feed- report .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **319** of **763** transport and sequestration costs

– approximately $5
- $15 per ton of CO 2 - are based on DOE NETL studies and are also consistent with other published studies . 337 For transport, costs reflect pipeline capital costs , related capital expenditures, and O&M costs . S equestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection . These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for ge ologic sequestration of CO 2 in deep saline formations , which are discussed further in sections V. M . and N below . 338 Based on DOE/NETL studies, the EPA estimated that the total CO 2 transportation, storage, and monitoring ( TSM ) cost associated with EGU CCS would comprise less than 5.5 percent of the total
337 Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases (DOE/NETL
- 341/082312); Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture (DOE/NETL
2011/1498); Cost and Performance Baseline for Fossil Energ y Plants (DOE/NETL
- 2010/1397); Economic Evaluation of CO2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002 ; Carbon Dioxide and Transport and Storage Costs in NETL Studies ( DOE/NE TL - 2013/1614), March 2013; Carbon Dioxide and Transport and Storage Costs in NETL Studies ( DOE/NETL
- 2014/1653 ) , May 2014; Cost and Performance Baseline for Fossil Energy Power Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity ( DOE -NETL - 2015/1723 ) , July 2015 . 338 Carbon Dioxide and Transport and Storage Costs in NETL Studies. DOE/NETL
- 2013/1614. March 2013. P. 13.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **320** of **763** cost of electricity in all capture cases modeled
- approximately $5
- $15 per ton of CO 2 . 339 The range of TSM costs the EPA relied on are broadly consistent with estimates provided by the Global Carbon Capture and Storage Institute as well . 340 Some c ommenters suggested that the EPA underestimated the costs associated with transporting captured CO 2 from an EGU to a sequestration site. 341 Specifically, commenters suggested that the EPA’s estimated costs for constructing pipelines were lower than costs based on actual industry experience. Commenters also opined that the EPA’s assumed length of pipeline needed between the EGU and the sequest ration site is not reasonable and that the DOE /NETL study 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 and sequestration costs are reasonable. First, the E PA in fact include s cost estimates for CO 2 transport when EOR opportunities are not available

– consistent with its overall conservative cost methodology of assuming no revenues from sale of captured CO 2 . Specifically, the EPA estimate s transport, storage and

339 RIA at section 5.5; proposed rule RIA at 5
- 30. 340 http:// hub .globalccsinstitute.com/ sites/default/files/ publicatio ns/ 12786/ economic
- assessment - carbon - capture - and- storage technologies
- 2011
- update. pdf . 341 See, for example, comments from American Electric, pp 97
- 8, Southern Company, pp. 47 - 48, and Duke Power p. 98 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **321** of **7 63**  monitoring ( TSM ) costs of $5
- $15 per ton of CO 2 for non -EOR applications. 342 This estimate is reflected in the LCOE comparative costs. 343 The EPA also carefully reviewed the assumptions on which the transport cost estimates are based and continues to find them reasonable. The NETL studies referenced in Section V.I.2 above based transport costs on a generic 100 km (62 mi) pipeline and a generic 80 ki lometer pipeline . 344 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. 345 As a point of reference, the longest CO 2 pipeline in the United States is 502 miles. 346 For new sources, pipeline distance and costs can be factored into siting and, as discussed in section V. M , there is widespread availability of geologic formations for geologic sequestration ( GS ) . Moreover, data from the Pipeline and Hazardous Materials Safety
342 See RIA at section 5.5 and proposed RIA at 5 - 30 . 343 See RIA at section 5.5 . 344 The pipeline diameter was sized for this to be achieved without the need for recompression stages along the pipeline length. 345 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic Storage: A Key Component of a Global Energy Technology Strategy to Address Climate Change. Joint Global Change Research Institute, Battelle Pacific Northwest Division. PNWD
- 3602. College Park, MD. 346 A Review of the CO 2 Pipeline Infrastructure in the U.S., April 21, 2015, DOE/NETL
- 2014/1681, Office of Fossil Energy, National Energy Technology Laboratory.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **322** of **763** Administration show that in 2013 there were 5,195 miles of CO 2 pipelines operating in the United States. This represents 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 its estimates have a reasoned basis. See also section V. M below further discussing the current availability of CO 2 pipelines. With respect to sequestration , certain commenters argued that the EPA’s cost analysis failed to account for many contingencies and uncertainties (surface and sub
- surface property rights in particular), ignored the costs of GHGRP subpart RR, and also was not representative of the costs
as sociated with specific GS site characterization, development, and operation/injection of monitoring wells. Commenter American Electric Power (AEP) referred to its own experience with the Mountaineer demonstration project. AEP noted that although this proje ct was not full scale, finding a suitable repository, notwithstanding a generally favorable geologic area, proved difficult. The company referred to its estimated cost of expanding the existing Mountaineer plant to a larger scale project, particularly the cost of site characterization and well construction . 347

347 AEP Comments at pp. 93, 96.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **323** of **763** The EPA’s cost estimates account for the requirements of the Underground Injection Control Class VI program, and GHGRP subpart RR , among them site screening and evaluation 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 also reflect costs for sub - surface pore volume property rights acquisition . 348 These estimates are consistent with the costs presented in the study CO2 Storage and Sink Enhancements: Developing Comparable Economics , which incorporates the costs ass ociated with site evaluation, well drilling, and the capital equipment required for transporting and injecting CO 2 . 349 , 350 Monitoring costs were evaluated based on the methodology set forth in the
348 “ Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture. ” DOE/NETL
- 2011/1498 ( September 2013 ) p. 49. Specifically, the report estimates the costs associated with acquiring rights to use the pore space in the geologic formation. Costs are estimated based on studies of subsurface rights acquisition for natural gas storage. The report also estimates costs for land acquisition for surface property rights. Id. p. 48. 349 Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D G. De La Torre Ugarte, and D. Simbeck. (2003). Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Fina l Technical Report Prepared by Tennessee Valley Authorit y for DOE . 350 As noted above, o ther sequestration
- related costs are also estimated, including injection wells and equipment, pore volume acquisition , and long- term- liability . “ Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2a, September 2013 DOE/NETL - 2010/1397 , p. 55 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **324** of **763** International Energy Agency Greenhouse Gas R&D Programme’s Overview of Monitoring Projects for Geologic Storage Projects report. 351 The EPA’s cost estimates for sequestration thus cover all aspects commenters claimed the EPA disregarded. The EPA believes that the use of costs and scenarios presented in the studies referenced are representative for purposes of the cost analysis. The NETL cost estimates upon which the EPA’s costs draw directly from the UIC Class VI economic impact analysis. 352 That analysis is based on estimated characteristics for a represent ative group of projects over a 50
- year period of analysis, as well as industry averages for several cost components and sub
components. The EPA also made reasonable assumptions regarding the assumed injection site: a deep saline formation with typical characteristics (e.g., representative depth and pressure). 353 With respect to AEP’s experience with the Mountaineer demonstration project, sequestration siting issues are of course

351 “ Overview of Monitoring Requirement s for Geologic Storage Projects ”, IEA Greenhouse Gas R&D Programme, Repo rt Number PH4/29, November 2004 . 352 Cost Analysis for the Federal Requirements Under the Underground Inject ion Control Program for Carbon Dioxide Geologic Sequestration Wells , U.S. Environmental Protection Agency Office of Water, EPA 816
-R10
- 013, November 2010, pages 3
- 1 , 5 - 42. 353 Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **325** of **763** site
- specific, and raise individual issues. For this reason, it is inappropriate to generalize from a particular individual experience. In this regard, as explained in Section V. N below, the construction permits is sued by EPA to - date under the Underground Injection Control Class VI regulations required far fewer wells for site characterization and monitoring than AEP found to be necessary at its Mountaineer site. Moreover, notwithstanding difficulties, the company was able to successfully dril l and complete wells, and safely inject captured CO 2 . The company also indicated it fully expected to be able to do so at full scale and explained how. 354 For discussion of 40 C FR Part 98 subpart RR (the GHGRP requirements 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 properly designed and operated. As discussed elsewhere, the final standard
354 See “ CCS front end engineering & design report: American Electric Power Mountaineer CCS II Project. Phase 1 ” at pp. 36
- 43. The company likewise explained the monitoring regime it would utilize to verify containment, and the well construction it would utilize to guarantee secure sequestration. Id. at pp. 44 - 54. Available at: http://www.globalccsinstitute.com/publications/aep
-mountaineer
ii
-project
- front - end- engineering
- and- design
- feed- report***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **326** of **763** reflects the degree of emission limitation achievable through the application of the BSER which we have determined 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 approximately 16 percent. In determining the predicted cost and performance of such a system, the EPA utilized information contained in updated DOE/NETL studies that assumed use of bituminous coal and an 85 percent capacity factor. Here we examine the effects of deviating from those assumed operational parameters on the achievability of the final standard of performance. 355 This is in keeping with the requirement that a standard of performance must be achievable accounting for all normal operating variability when a control system is properly designed, maintained, 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
-hour s) over
355 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
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– Do Not Cite, Quote or Release During Review *** Page **327** of **763** the same 12 operational months. Such a compliance averaging period is very forgiving of short
- term excursions that can be associated with non
- routine events such as start
- ups, shutdowns, and malfunctions. A new fossil fuel
- fired steam generating EGU
– if constructed

– would, most likely, be built to serve base load power demand and would not be expected to routinely start
- up or shutdown 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. Malfunctions are unplanned and unpredictable events and emission excursions can happen at or around the time of the equipment malfunction. But a malfunctioning EGU that cannot be operated properly should be shut down until the malfunctioning equipment can be addressed and the EGU can be restarted to operate properly. The post - combustion capture systems that have been uti lized have proven to be reliable. The Boundary Dam facility has been operating full CCS successfully at commercial scale since October 2014. As described earlier, in evaluating results from the Mountaineer slip
- stream demonstration, AEP and Alstom reported robust steady- state operation dur ing all modes of power***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **328** of **763** plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent. 356 2. Variations in coal type The use of specific coal types can affect the amount 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 units. Based on those reports, the EPA predicts that a new SCPC burning low rank coal ( subbituminous coal or dried lignite ) would have an uncontrolled emission rate about 7 percent higher than a similar unit firing typical bituminous coal. 357 The EPA predicts that such a highly efficient new SCPC utilizing subbituminous coal or dried lignite would need to capture approximately 23 percent of the CO 2 . The EPA also believes that it is technically feasible to do so, although additional cost would be entailed. The EPA has

356 http://www.alstom.com/press
- centre/2011/5/alstom
- announces sucessful - results - of -mountaineer
- carbon - capture - andsequestration
- ccs -project/. The Boundary Dam facility likewise is operating reliably (see section V.D.3.a above ). See also “Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3”, DOE/ NETL - 2015 /1723 (July 2015) at p. 36 (“[t]he capture and CO 2 compression technologies have commercial operating experience with demonstrated ability for high reliability”). 357 For additional detail, see the Technical Support Document (TSD)

– “Achievability of the Standard for Newly Constructed Steam Generating EGUs ”

– available in the rulemaking docket.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **329** of **763** evaluated those costs and finds them to remain reasonable. 358 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 capital cost using these coal types would also be somewhat higher, an estimated 2 3 percent increase. 359 The EPA finds these increases to be reasonable because , as discussed earlier, the costs are reasonably consistent with capital cost increases in previous NSPS. See section V.H.4 above. K. Emission Reductions Utilizing Partial CCS Although the def inition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources and the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must do so. See Sierra Club v. Costle , 657 F.2d at 326 (“we can think of no sensib le interpretation of the statutory words “best ... system” which would not incorporate the

358 The cost of the lignite drying equipment is assumed to be low compared to the cost of the carbon capture equipment. Further, pre - drying of the lignite reduces fuel, auxiliary power consumption and other O&M costs. www.iea
coal.org.uk/documents/83436/9095/Techno
- economics
- of -modern -pre drying
- technologies
- for - lignite
- fired
-power -plants, - CCC/ 241 359 Note that the 23 percent increase in expected capital costs and the 23 percent CO 2 capture needed to meet the final standard are coincidental and are not correlated.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **330** of **763** amount of air pollution as a relevant factor to be weighed when determining the optimal standard for controlling ... emissions”). 360 This is consistent with the Court’s st atements 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 degree’” . The final standard of performance will result in meaningful and significant emission reductions of GHG emissions from a new coal - fired steam generating unit. The EPA estimates that a new highly efficient 500 MW coal
- fired SCPC meeting the final standard of 1,400 lb CO 2 /MWh - g will emit about 354 ,0 00 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 361 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 highly efficient SCPC unit that includes partial CCS
- the highly efficient 500 MW coal - fired SCPC with partial CCS would emit about 675,000
360 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 system’’ to read, “best technological system.” The 1990 CAAA deleted “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 amount of a ir emissions remains valid for the phrase “best system.” 361 U sing U.S. EPA Office of Transportation and Air Quality (OTAQ) estimate of average vehic le emissions of 4.7 tonnes/year.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **331** of **763** fewer metric tons of CO 2 each year than that from a new, less
e fficient coal
- fired utility boiler with an assumed emission of 1,800 lb CO 2 /MWh - g . For comparison, see Table 12 below which provides the amount of CO 2 emissions captured each year by other CCS projects. These result show that, even though the emission reductions are significant, they are reasonably within the range of emission reductions that are currently being achieved now in existing facilities. For comparison, approximately 60,000,000 metric tons of CO 2 were supplied to U.S. EOR operations in 2013. 362 **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 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
362 Greenhouse Gas Reporting Program, data reported as of August 18, 201 4 . 363 See 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 Techno logies to Control Sulfur Dioxide Emissions from Stationary Sources,” MA dissertation submitted to the Carnegie Institute of Technology, Carnegie Mellon University in partial fulfillment of the requirements for the degree of Doctor of Philosophy in Engineer ing and Public Policy, Pittsburgh, PA, January 2001.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **332** of **763** Petra Nova/NRG WA Parish 1, 4 00,000 Dakota Gasification 3,000,000
L . Further Development and Deployment of CCS Technology Researchers at Carnegie Mellon University (CMU) have studied the history and the technological response to environmental regulations. 363 By examining U.S. research funding and patenting activity over the past century, the CMU researchers found that promulgation of national policy requiring large reductions in power
-plant emissions resulted in a significant upswi ng in inventive activity to develop technologies to reduce those emissions. The researchers found that, following the 1970 Clean Air Act, there was a 10
- fold increase in patenting activity directed at improving the SO 2 scrubbers that were needed to comply with stringent federal and state - level standards. Much like carbon capture scrubbers today, the technology to capture and remove SO 2 from power plant flue gases was new to the

363 See 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 Techno logies to Control Sulfur Dioxide Emissions from Stationary Sources,” MA dissertation submitted to the Carnegie Institute of Technology, Carnegie Mellon University in partial fulfillment of the requirements for the degree of Doctor of Philosophy in Engineer ing and Public Policy, Pittsburgh, PA, January 2001.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **333** of **763** industry and was not yet widely deployed at large coal -burning plants when the E PA first promulgated the 1971 standards . Many of the early Flue Gas Desulfurization ( FGD ) units did not perform well , as the technology at that time was poorly understood and there was little or no prior experience on coal
fired power plants. In contrast, amine
-based capture systems have a much longer history of reliable use at coal
- fired plants and other industrial sources. There is also a better understanding of the amine process chemistry and overall process design

– and project developers have much sophisticated analytical tools available today than in the 1970s during the development of FGD scrubber technologies. While R&D efforts were essential to achieving improvements in FGD scrubber technology

– and are also very impo rtant to improving carbon capture technologies , the influence of regulatory actions that establish commercial markets for advanced technologies cannot be minimized. The existence of national government regulation for SO 2 emissions control stimulated innovation, as shown by the patent analysis following initial SO 2 regulatory requirements for EGU emissions. The study author further found that regulatory stringency appears to be particularly important as a driver of innovation, both in terms of inventive activity and in terms of the communication processes involved in knowledge transfer and diffusion. Further,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **334** of **763** as electric power generation doubled, the operating and maintenance costs of FGD systems decline to 83 percent of their original level. This finding, which is very much in line with progress ratios determined in other industries, shows that quantifiable technological improvements can be shown to occur solely on the basis of the experience of operating an environmental control technology forced into bei ng by government actions . M. Technical and Geographic Aspects of Disposition of Captured CO2 In the following sections of the preamble, we discuss issues associated with the disposition of captured CO 2 : the “S” - sequestration

– in CCS. In th is section, we review the existing processes, technologies, and geologic conditions that enable successful geologic sequestration (GS). In Section V. N ., we discuss in detail the comprehensive, in
-place regulatory structure that is currently available to over see GS projects and assure their safety and effectiveness. Together , these discussions demonstrate that the technical feasibility of GS, another key component of a partial CCS unit, is adequately demonstrated. S equestration 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 mechanisms, along***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **335** of **763** with the regulatory requirements and safeguards of the Underground Injection Control Program and complementary 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 leakage using Safe Drinking Water Act (SDWA) and CAA authorities (see Section V. N of this preamble ) . 364 1. Geologic and Geographic C onsiderations for GS Geologic sequestration (i.e., long
- term containment of a CO 2 stream in subsurface geologic formations) is technically feasible and available throughout most of the United States. GS is based on a demonstrated understanding of the processes that affect CO 2 fate in the subsurface; these processes can vary regionally as the subsurface geology changes. GS occurs through a combination of mechanisms including: 1) structural and stratigraphic trapping (generally trapping below a low permeability confining layer); 2) residual CO 2 trapping

364 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 climate change mitigation program that involves capturing carbon dioxide from industrial sources, compressing it into a ‘supercritical fluid,’ and injecting that fluid underground for the purposes 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 carbon dioxide

– involves that injection of fluid into underground wells, it is subject to regulation under the Safe Drinking Water Act”).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **336** of **763** (retention as an immobile phase trapped in the pore spaces of the geologic formation); 3) solubility trapping (dissolution in the in situ formation fluids); 4) mineral trapping (reaction with the minerals in the geologic formation and confining layer to produce carbonate minerals); and 5) p referential adsorption trapping (adsorption onto organic matter in coal and shale). 365 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 widespread throughout most parts of the United States. Storage security is expect ed to increase over time through post - closure , resulting in a decrease in potential risks. 366 This expectation is based in part on a technical understanding of the variety of trapping mechanisms that work to reduce CO 2 mobility over time. 367 In addition, site characterization, site operations, and monitoring strategies can work in combination to promote storage security. The effectiveness of long
- term trapping of CO 2 has been demonstrated by natural analogs in a range of geologic settings
365 See, e.g., USEPA. 2008. Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide. 366 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010), page 47. 367 See, e.g., Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **337** of **763** where CO 2 has remained trapped for millions of years. 368 For example, CO 2 has been trapped for more than 65 million years in the Jackson Dome, located near Jackson, Mississippi. 369 Other examples of natural CO 2 sources include Bravo Dome and McElmo Dome in Colorado and New Mexico , respectively . These natural storage sites are themselves capable of holding volumes 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 Department of Energy (DOE) estimated current CO 2 reserves of 594 million metric tons at Jackson Dome, 424 mi llion metric tons at Bravo Dome, and 530 million metric tons at McElmo Dome. 370 GS is feasible in different types of geologic formations including deep saline formations (formations with high salinity formation fluids) or in oil and gas formations, such as where injected CO 2 increases oil production efficiency through a process referred to as enhanced oil recovery (EOR). Both deep saline and oil and gas formation types are widely available in the United States. The geographic availability of deep saline

368 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. 369 Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage. 370 DiPietro, P., Balash, P. & M. Wallace. A Note on Sources of CO 2 Supply for Enhanced- Oil Recovery Operations. SPE Economics & Management. April 2012.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **338** of **763** formations and EOR is shown in Figure 1 below . 371 As shown in the figure, there are 39 states for which onshore and offshore deep saline formation storage capacity has been identified. 372 EOR operations are currently being conducted in 12 states. An additional 17 states have geology that is amenable to EOR operations. Figure 1 also shows areas that are within 100 kilometers (62 miles) of where storage capacity has been identified. 373 There a re 10 states with operating CO 2 pipelines and 18 states that are within 100 kilometers (62 miles) of an active EOR location. CO 2 may also be used for other types of enhanced recovery, such as for natural gas production. Reservoirs such as unmineable coal seams also offer the potential for geologic storage. 374 Enhanced coalbed methane recovery is the process of injecting and storing CO 2 in unmineable coal seams to enhance methane recovery. These operations take advantage of the preferential chemical affinity of coal for CO 2 relative to the
371 A color version of the figure, which readers may find easier to view, can be found in the technical support document on geographic availability in the rulemaking docket. 372 Alaska is not shown in Figure 1 ; it has deep saline formation storage capacit y, geology amenable to EOR operations, and potential GS capacity in unmineable coal seams . 373 The distance of 100 kilometers reflects assumptions in DOE
NETL cost estimates which the EPA used for cost estimation purposes. See “ Carbon Dioxide and Transport and Storage Costs in NETL Studies ”, DOE/NETL
- 2014/1653 ( May 2014 ). 374 Other types of opportunities include organic shales and basalt.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **339** of **763** 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. This process effectively “locks” the CO 2 to the coal, where it remains stored. DOE has identified over 54 billion metric tons of potential CO 2 storage capacity in unmineable coal a cross 21 states. 375 The availability of unmineable coal seams is shown in Figure 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, i n some cases, demand in those states can be served by coal - fired power plants located in
areas suitable for GS, and in other cases, coal
- fired power plants are unlikely to be built in those areas for other reasons, such as the lack of available coal or state law prohibitions and restrictions against coal
- fired power plants. 376

375 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL). 376 Similarly, as discussed below , the U.S. territories lack available coal, do no t currently have coal - fired power plants, and, as a result, are not expected to see new coal - fired power plants. Hawaii is not expected to constructed new coal plants as it intends to utilize 100 percent renewable energy sources by 2050.***EO 12866_Review
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**Figure 1**  **: Geologic Sequestration in the Continental United States** ***EO 12866_Review
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**Figure 2 –**  **Electrical Transmission Lines a** **cross the Continental United States**  **377**
377 Ventyx Velocity Suite Online. April 2015.***EO 12866_Review
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2 . Availability of Geologic Sequestration in Deep Saline Formations The DOE and the United States Geological Survey (USGS) 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 and Geographic Information System (NATCARB) using volumetric models and published in a Carbon Utilization and Storage Atlas. 378 DOE estimates that areas of the United States with appropriate 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 geologic characteristics that are amenable to deep saline GS in either onshore or offshore locations. In 2013, the USGS completed its evaluation of the technically accessible GS resources for CO 2 in U.S. onshore areas and state waters using probabilistic
a ssessment. 379 The USGS estimates a mean of 3,000 billion metric tons of subsurface CO 2 sequestration potential, including saline
378 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL). 379 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment of geologic carbon dioxide storage resources

—Results: U.S. Geological Survey Circular 1386, p. 41, http://pubs.usgs.gov/circ/1386/ .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **343** of **763** and oil and gas reservoirs, across the basins studied in the United States. The DOE has created a network of seven Regional Carbon Sequestration Partnerships (RCSPs) to deploy large - scale field projects in different geologic settings across the country to demonstrate that GS can be achieved safely, permanently, and economically at large scales. Collectively, the seven RCSPs represent regions encompassing 97 percent of coal
- fired CO 2 emissions, 97 percent of industrial CO 2 emissions, 96 percent of the total land mass, and essentially all the geologic sequestration sites in the United St ates potentially available for GS. 380 The seven partnerships include more than 400 organizations spanning 43 states (and four Canadian provinces). 381 RCSP p roject objectives are to inject at least one million metric tons of CO 2 . In April 2015, DOE announced that CCS projects supported by the department have safely and permanently stored 10 million metric tons of CO 2 . 382 E ight RCSP “Development Phase” projects have been initiated and five of the eight projects are injecting or have completed CO 2 injection into deep saline formations. Three of these
380 http://energy.gov/fe/science
- innovation/carbon
- capture - andstorage - research/regional
-partnerships . 381 http://energy.gov/fe/science
- innovation/carbon
- capture - andstorage - research/regional
-partnerships . 382 http://energy.gov/articles/milestone
- energy- department projects
- safely- and-permanently- store - 10
-million
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– Do Not Cite, Quote or Release During Review *** Page **344** of **763** projects have already injected more than one million metric tons each, and one, the Cranfield Site, injected over eight million metric tons of CO 2 between 2009 and 2013. 383 Various types of technologies for monitoring CO 2 in the subsurface and air have been employed at these projects, such as seismic methods (crosswell seismic, 3
- D and 4 - D seismic, and vertical seismic profiling), atmospheric CO 2 monitoring, soil gas sampling, well and formation pressure monitoring, and surface and ground water monitoring. 384 No CO 2 leakage has been reported from these sites, which further supports the availability of effective GS. 3 . Availability of CO 2 Storage via EOR Although the determination that the BSER is adequately demonstrated and the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securely sequestering CO 2 via EOR. EOR is a technique that is used to increase the production of oil . Approaches used for EOR include steam injection,

383 U.S. Department of Energy, National Energy Technology Laboratory, Project Facts, Southeast Regional Carbon Sequestration Partnership

—Deve lopment Phase, Cranfield Site and Citronelle Site Projects, NT42590, October 2013. Available at: http://www.netl.doe.gov/publications/factsheets/project/NT42590. pdf . 384 A description of the types of monitoring technologies employed at RCSP projects can be found here: http://www.netl.doe.gov/research/coal/carbon
- storage/carbon
storage - infrastructure/regional
-partnership
- development -phase iii .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **345** of **763** injection of specific fluids such as surfactants and 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 hydrocarbons, native formation fluids, and CO 2 . The gaseous CO 2 - rich stream then is typically dehydrated, purified to remove hydrocarbons,
re - compressed, and re - injected into the reservoir to 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 dissolved in the oil and water that is not recovered. The CO 2 that remains in the reservoir is not mobile and becomes sequestered. The amount of CO 2 used in an EOR project depends on the volume and injectivity of the reservoir that is being flooded and the length of time the EOR project has been in operation. Initi ally, 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 reservoir in addition to new CO 2 that is received. If an EOR operator will not***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **346** of **763** 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 c ome from anthropogenic or natural 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 Materials Safety Administration found at 49 CFR part 195 (Transportation 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 transport companies have specifications related to the composition of the CO 2 stream. The regulatory requirements and company specifications ensure EOR operators receive a known and consistent CO 2 stream. EOR has been successfully used at numerous production fields throughout the United States to increase oil recovery. The oil industry in the United States has over 40 years of
experience with EOR. An oil industry study in 2014 identified***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **347** of **763** more than 125 EOR projects in 98 fields in the United States. 385 More than half of the projects evaluated in the study have been in operation for more than 10 years, and many have been in operation for more than 30 years. This experience provides 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 deployment of CCS across geographically diverse areas. Currently, 12 states have active EOR operations and most have developed an extensive CO 2 infrastructure, including pipelines, to support the continued operation and growth of EOR. An additional 18 states are within 100 kilometers (62 miles) of current EOR operations. See Figure 1 above. The vast majority of EOR is conducted in oil reservoirs in the Permian Basin, which extends through southwest Texas and southeast New Mexic o. S tates where EOR is utilized include Alabama, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. Several commenters raised concerns about the volume of CO 2 used in EOR projects relative to the scale of EGU emissions and the demand for CO 2 for EOR projects. At the project level, the volume of CO 2 already injected for EOR and the duration of

385 Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7, 2014 (correcte d tables appear in Volume 112 , I ssue 5, May 5, 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **348** of **763** operations are of similar magnitude to the duration and volume of CO 2 expected to be captured from fossil fuel
- fired EGUs. The volume of CO 2 used in EOR operations can be large (e.g., 55 million tons of CO 2 were stored in the SACROC unit in the Permian Basin over 35 years) , and operations at a single oil field may last for decades , injecting into multiple parts of the field. 386 According to data reported to the EPA’s GHGRP, approximately 60 million metric tons of CO 2 were supplied to EOR in the United States in 2013. 387 Approximately 70 percent of this total CO 2 supplied was produced from natural (geologic) CO 2 sources and approximately 30 percent was captured from anthropogenic
sources. 388 A DOE - sponsored study has analyzed the geographic availability of applying EOR in 11 major oil producing regions of the United States and found that there is an opportunity to significantly increase the application of EOR to areas outside of current operations. 389 DOE - sponsored geologic and engineering

386 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. 387 Greenhouse Gas Reporting Program, data reported as of August 18, 201 4 . 388 Greenhouse Gas Reporting Program, data reported as of August 18, 201 4 . 389 “Improving Domestic Energy Security and Lowering CO 2 Emissions with “Next Generation” CO 2 -Enhanced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Available at:***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **349** of **763** analyses show that expanding EOR operations into areas additional to the capacit y already identified and applying 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 that 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. 390 DOE’s Carbon Utilization and Storage Atlas identifies 29 states with oil reservoirs amenable to EOR , 12 of which currently have active EOR operations . A comparison of the current states with EOR operations and the states with potential for EOR shows that an opportunity exists to expand the use of EOR to regions outside of current areas. The availability of anthropogenic CO 2 in areas outside of cur rent sources could drive new EOR projects by making more CO 2 locally available. Some commenters raised concerns that data are extremely limited on the extent to which EOR operations permanently sequester CO 2 , and the efficacy of long term storage, or that the http://www.netl.doe.gov/research/energy
analysis/publications/details?pub=df02ffba
- 6b4b
- 4721
- a7b4 - 04a505a19185 . 390 “Improving Domestic Energy S ecurity and Lowering CO 2 Emissions with “Next Generation” CO 2 -Enhanced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Available at: http://www.netl.doe.gov/research/energy
analysis/publications/details?pub=df02ffba
- 6b4b
- 4721
- a7b4 - 04a505a19185 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **350** of **763** 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 studied 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 Permian basin since 1972 for EOR purposes. One study evaluated a portion of this project, and estimated that the injection operations resulted in final sequestration of about 55 million tons of CO 2 . 391 This study used modeling and simulations, along with collection and analysis of seismic surveys , and well logging data, to evaluate the ongoing and potential CO 2 trapping occurring through various mechanisms. The monitoring at this site demonstrated that CO 2 can become trapped in geologic formations. In a separate study in the SACROC Unit, the Texas Bureau of Economic Geology conducted an extensive groundwater sampling program to look for evidence of CO 2

391 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
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– Do Not Cite, Quote or Release During Review *** Page **351** of **763** leakage in the shallow freshwater aquifers. No evidence of leakage was detected. 392

 The International Energy Agency Greenhouse Gas Programme conducted an extensive monitoring program at the Weyburn oil field in Saskatchewan between 2000 and 2010 (the site 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, seismic surveys and wellbo re integrity testing. An extensive shallow groundwater monitoring program revealed no significant changes in water chemistry that could be attributed to CO 2 storage operations. 393 The International Energy Agency Greenhouse Gas Programme developed a best prac tices manual for CO 2 monitoring at EOR sites based on the comprehensive

392 Romanak, K.D., Smyth, R.C., Yang, C., and Hovorka, S., Detection of anthropogenic CO 2 in dilute groundwater: field observations and geochemical modeling o f 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 Series #10
- 06. 393 Roston, B., and S. Whittaker (2010), 10+ year s of the IEA- GHG Weyburn -Midale CO 2 monitoring and storage project; success and lessons learned from multiple hydrogeological investigations, to be published in Energy Procedia, Elsevier, Proceedings of 10th International Conference on Greenhouse Gas Control Technologies, IEA Greenhouse Gas Programme, Amsterdam, The Netherlands.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **352** of **763** analysis of surface and subsurface monitoring methods applied over the 10 years. 394

 The Texas Bureau of Economic Geology also has been testing a wide range of surface and subsurface moni toring tools and approaches to document sequestration efficiency and sequestration permanence at the Cranfield oilfield in Mississippi (see Section L .1 above). 395 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/year. Texas Bureau of Economic Geology is currently evaluating the res ults of several monitoring techniques employed at the Cranfield project and preliminary findings indicate no impact to groundwater. 396 The project also demonstrates the availability and effectiveness of many different monitoring techniques 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 Figure 1, the United States has widespread potential for storage, including in deep saline formations and oil and gas formations. 394 Hitchon, B. (Editor), 2012, Best Practices for Validating CO 2 Geological Storage: Geoscience Publishing, p. 353. 395 http://www.beg.utexas.edu/gccc/cranfield.php . 396 http://www.beg.utexas.edu/gccc/cranfield.php .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **353** of **763** However, s ome c ommenters maintained that the EPA’s information regarding availability of GS sites is overly general and ignores important individual considerations. A number of commenters, for example, maintained that site conditions often make monitor ing difficult or impossible, so that sites are not available as a practical matter. 397 Commenter American Electric Power pointed to its own experience in siting monitoring wells for its pilot plant Mountaineer CCS project, which involved protracted time and expense to eventually site monitoring wells. 398 Other commenters noted significant geographic disparity in GS site availability, claiming absence of sites in southeastern areas of the country. 399 Project
- and site
- specific factors do influence where CO 2 can be safely sequestered. However, as outlined above, there is widespread potential for GS in the United States . If an area does not have a suitable GS site, EGUs can either transport 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 lines (see Figure 2 and section M. 7 ) . In addition, there are alternative means of complying with the final standards of performance that
397 Comments of Southern Co., p. 38. 398 Comments of AEP pp. 93, 96. 399 Comments of Duke Energy, pp. 24
- 5; UARG, pp. 53, 57 citing Cichanowicz (2012).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **354** of **763** do not necessitate use of partial CCS, so any siting 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 satisfying, since , among other things, there were alternative methods of compliance available should a new kiln of this older design be built. 4 . Alternatives to Ge ologic S equestration Potential alternatives to sequestering CO 2 in geologic formations are emerging. These relatively new potential alternatives may offer the opportunity to offset the cost of CO 2 capture. For example, captured anthropogenic CO 2 may be stored in solid carbonate materials such as precipitated calcium carbonate (PCC) or magnesium or calcium carbonate, bauxite residue carbonation, and certain types of cement through mineralization. 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 p roduced can be tailored to optimize performance in specific industrial and commercial applications. These carbonate materials have been used in the construction industry and, more***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **355** of **763** recently and innovatively, in cement production processes to replace Portland cement. The Skyonics Skymine project, which opened its demonstration project in October 2014, is an example of captured CO 2 being used in the production of carbonate products. This plant converts CO 2 into commercial products. It captures over 75,000 tons of CO 2 annually from a San Antonio, Texas, cement plant and converts the CO 2 into other products, including sodium carbonate, sodium bicarbonate, hydrochloric acid and bleach. 400 A few commenters suggested that CO 2 utilization technologies alternative to GS are being commercialized, and that these should be included as compliance options for this rule. The rule generally requires that captured CO 2 be either injected on
- site for geologic sequestration or transferred offsite to a facil ity reporting under 40 CFR subpart RR. The EPA does not believe that the emerging technologies just discussed are sufficiently advanced to unqualifiedly structure this final rule to allow for their use . Nor are there plenary systems of regulatory control and GHG reporting for these approaches, as there are for geologic sequestration. Nonetheless, as stated above, these technologies not only show promise, but could potentially be demonstrated to show permanent storage of CO 2 .

400 http://skyonic.com/technologies/skymine .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **356** of **763** In the January 2014 proposal, the EPA noted that it would need to adopt a mechanism to evaluate these alternative technologies before any could be used in lieu of geologic sequestration. 79 FR at 1484. The EPA is establishing such a mechanism in this final rule. See §60.5555(g) . The rule provides for a case -by- case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non
- geologic 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 analogous mechanism for case
-by- case approval of innovative technological systems of continuous emission reduc tion which have not been adequately demonstrated. Applicants would need to demonstrate that the proposed technology would operate effectively, and that captured CO 2 would be permanently stored. Applicants must also demonstrate that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare or safety. In evaluating applications, the EPA may conduct tests itself or require the applicant to conduct testing in support of its application. Any application would be publi cly noticed, and the EPA would solicit comment on the application and on intended action the EPA might take. The EPA could also provide a conditional approval of an application on operating results from***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **357** of **763** a proscribed period. The EPA could also terminate an approval, including a termination based on operating results calling into question a technology’s effectiveness. As noted at proposal, given the unlikelihood of new coal
fired EGUs being constructed, the EPA does not expect there to be many (if any) applic ations for use of non
- geologic sequestration technology. 79 FR at 1484. 5 . Availability of Existing or P lanned CO 2 P ipelines CO 2 pipelines are the most economical and efficient method of transporting large quantities of CO 2 . 401 CO 2 has been transported via pipelines in the United States for nearly 40 years. Over this time, the design, construction, operation, 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 Administration (PHMSA) reported that in 2013 there were 5,195 miles of CO 2 pipelines operating in the United States. This represents a seven percent increase i n CO 2 pipeline miles over the previous year and a 38 percent increase in CO 2 pipeline miles since 2004. 402

401 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010), page 36. 402 “Annual Report Mileage for Hazardous Liquid or Carbon Dioxide Systems ”, U.S. Pipeline and Hazardous Materials Safety Administration, March 2, 2015 . Available at: http://www.phmsa.dot.gov/ pipeline/library/data
- stats .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **358** of **763** 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 St ates. The EPA does not agree. The CO 2 pipeline network in the United States has almost doubled in the past ten years 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
ne twork. Several hundred miles of dedicated CO 2 pipeline are under construction, planned, or proposed, including projects in Colorado, Louisiana, Montana, New Mexico, Texas, and Wyoming. Examples are identified below.

 Kinder Morgan has reported several proposed pipeline projects including the proposed expansion of the existing 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 expansion of CO 2 production capacity at the McElmo Dome production facility in Colorado. The Cortez pipeline expansion is expected to be placed into service in 20 15. 403

403 “Form 10
-K: Annual Report Pursuant to Section 13 or 15(d) of the Security and Exchange Act of 1934, For the Fiscal Year Ended December 31, 2014”, Kinder Morgan, February 2015. Available at: http://ir .kindermorgan.com/sites/kindermorgan.investorhq.busines swire.com/files/report/additional/KMI
- 2014
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 Denbury reported that the company utilized approximately 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 associated pipelines in the Gulf Coast region. 404 Denbury also initiated transport of CO 2 from a Wyoming natural gas processing plant in 2013 and reported transporting approximately 22 million cubic feet per day of CO 2 in 2013 from that plant alone. 405

 Denbury completed the final section of the 325
-mile Green Pipeline for transporting CO 2 from Donaldsonville, Louisiana, to EOR oil fields in Texas. 406 Denbury completed construction and commenced operation of the 23 2
-mile Greencore Pipeline in 2013; the Greencore

404 “2013 Annual Report”, Denbury, April 2014. Available at http://www.denbury.com/files/doc_financials/2013/Denbury_Final_0 40814.pdf . 405 “CO 2 Sources ” , Denbury, 201 5 . Available at : http://www.denbury.com/operations/rocky
-mountain
- region/co2
- sources - and-pipelines/default.aspx . 406 http://www.denbury.com/ operations/gulf
- coast region/Pipelines/default.aspx.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **360** of **763** pipeline transports CO 2 to EOR fields in Wyoming and Montana. 407

 A project being constructed by NRG and JX Nippon Oil & Gas Exploration (Petra Nova) would capture CO 2 from a power plant in Fort Bend County, Texas for transport to EOR sites in Jackson County, Texas through an 82
-mile CO 2 pipeline. 408 The project is anticipated to commence operation in 2016. 409 Some commenters suggested that there may be challenges associated with the safety of transporting supercritical CO 2 over long distances, or that the EPA did not adequately consider the potential non
- air environmental impacts of the construction of CO 2 pipelines. The EPA has carefully evaluated the safety of pipelines 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, 3 54 (Jan. 3, 2014) .

407 “CO 2 P ipelines” , Denbury, 2014 . Available at : http://www.denbury.com/operations/rocky
-mountain
- region/COsub2
- sub - Pipeli nes/default.aspx . 408 “ The West Ranch CO 2 -EOR Project , NRG Fact Sheet”, NRG, 2014. Available at : www.nrg.com/documents/business/pla
- 2014
-west ranch - fact - sheet.pdf . 409 “WA Parish Carbon Capture Project ” , NRG, 2015. Available at: www.nrg.com/sustainability/strategy/enhance
- generation/carbon
capture/wa
-parish
- ccs -project/.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **361** of **763** Existing and new CO 2 pipelines are comprehensively regulated by the Department of Transportation’s Pipeline Hazardous Material Safety Administration. The regulations govern pipeline design, construction, operation and maintenance, and emergency response planning. See generally 49 CFR 195.2. Additional regulations address pipeline integrity management by requiring heightened scrutiny to assure the quality of pipeline integrity in areas with a higher potential for adverse consequences. See 49 CFR 195.450 and 195.452. On
- site pipelines are not subject to the Department of Transportation standards, but rather adhere to the Pressure Piping standards of the American Society of Mechanical Engineers (ASME B 31), which the EPA has found would ensure that piping and associated equipment meet certain quality 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 )). 410 These existing controls over CO 2 pipelines assure protective management, guard against releases, and assure that captured CO 2 will be securely conveyed to a sequestration site. 6 . States with Emission Standards That Would Re quire CCS

410 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
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– Do Not Cite, Quote or Release During Review *** Page **362** of **763** Several states have established emission performance standards or other measures to limit emissions of GHGs from new EGUs that are comparable to or more stringent than the final standard in this rulemaking. For example, in September 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 California Energy Commission and the California Public Utilities Commission. The Energy Commission has designed regulations that establish a standard for new and existing base load generation owned by, or under long- term contract to publicly owned utilities, of 1,100 lb CO 2 /MWh. In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any base load electric generation that commenced operation after June 1, 2008 and is located in Washington, whether or not that generation serves load located within the state. 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 Senate Bill 101, which mandated that facilities generating base load electricity, whether gas
- or coal - fired, must have emissions***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **363** of **763** equal to or less than 1,100 lb CO 2 /MWh, and prohibited utilities from entering into long
- term purchase agreements for base load
e lectricity with out
- of - state facilities that do not 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
- fired plants . In May 2007, Montana Governor Schweitzer signed House Bill 25, adopting a CO 2 emissions performance standard for EGU s in the state. House Bill 25 prohibits the state Public Utility Commission from approving new EGU s 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 otherwise emit; from 2016

– 2017, 70 percent must be captured and stored; and after 2017, 90 percent must be captured and stored. 7 . Coal -by-wire In addition, as discussed in the proposal, electricity demand in states that may not have geologic sequestration sites***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **364** of **763** 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 method, known as “coal -by-wire,” has long been used in the electricity sector because siting a coal
- fired power plant near the coal mine and transmitting the generation long distances to the load area is generally less expensive than siting the plant near the load area and shipping the coal long distances. For example, we noted in the proposal: “There are many examples where coal - fired power generated in one state is used to supply electricity in other state s. For instance, historically, nearly 40 percent of the power for the City of Los Angeles was provided from two coal
- fired power plants located in Arizona and Utah. In another example, Idaho Power, which serves customers in Idaho and Eastern Oregon, meets its demand 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 explore in greater detail the issue of coal
-by-wire and the abilit y of demand in areas without geologic sequestration to be served by coal generation located in areas that have access to geologic sequestration. Figure 1 of this preamble (a color version of which is provided as Figure 1 of the Geographic Availability***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **365** of **763** TSD) depicts areas of the country with: (1) existing 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) unmineable coal seams; and ( 7) areas 100 kilometers from geologic sequestration. As demonstrated by Figure 1, the vast majority of the country has existing or planned CO 2 pipeline, active CO 2 -EOR operations, the necessary geology for CO 2 storage, or is within 100 kilometers of areas with geologic sequestration. 411 A review of Figure 1 indicates limited areas that do not fall into these categories. As an initial matter, we note that the data included in Figure 1 is a conservative outlook of potential areas available for the development of CO 2 storage. We include only areas that have been assessed to date. Sizable portions of the United States have not yet been assessed and could reveal additional geologic formations suitable for CO 2 storage. 412

411 The NETL cost estimates for CO 2 transport assume a pipeline of 100 kilometers. NETL (2015) at p. 44. 412 The data in Figure 1 is based on estimates compiled by the DOE’s National Carbon Sequestration Database and Geographic Information System (NATCARB) and published in the United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition. As discussed in the TSD, deep saline formation potential was not assessed for Alaska, Connecticut, Hawaii, Maine, Massachusetts, Minnesota, Nevada, New Hampshire, Rhode Island, and Vermont. Oil and gas storage potential was not assessed for Alaska, Connecticut, Delaware, Hawaii, Idaho, Iowa, Maine,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **366** of **763** As one considers the areas on the map depicted in Figure 1 that fall outside of the above enumerated categories, in many instances, we find areas with low population density, 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 includes coal. In many of these areas, utilities, electric cooperatives, and municipalities have a history of joint ownership of coal
- fired generation outside the region or contracting with coal and other generation in outside areas to meet their demand. Some of the relevant areas are in RTOs 413 which engage in planning across the RTO, balancing supply and demand in real time throughout the RTO. Accordingly, generating resources in one part of the RTO such as a coal generator can serve load in other parts of the RTO, as well as load outside of the RTO. As we consider each of these geographic areas in the Geographic Availability TSD, we make key points as to why this final rule does not negatively impact the ability of these regions to access new coal Massachusetts, Minnesota, Missouri, Nevada, New Hampshire, North Carolina, Oregon, Rhode Island, South Carolina, Vermont, and Washington. Unmineable coal seams were not assessed for California, Connecticut, Delaware, Hawaii, Idaho, Maine, Massachusetts, Minnesota, Nevada, New Hampshire, New York, North Carolina, Oregon, Rhode Island, South Carolina, South Dakota, and Vermont. 413 In this discussion, we use the term RTO to indicate both ISOs and RTOs.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **367** of **763** generation to the extent that coal is needed to supply demand and/or those regions want to include new coal
- fired generation in their resource mix. N . Final Requirements for Disposition of Captured CO2 This section discusses the different regulatory components, already in place, that assure the safety and effectiveness of GS. This section, by demonstrating that GS is already 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 feasibility of GS is adequately demonstrated. In 2010, the EPA finalized an effective and coherent regulatory framework to ensure the long- term, secure and safe storage of large volumes of CO 2 . The EPA developed these Underground Injection Control (UIC) Class VI well regulations under authority of the Safe Drinking Water Act (SDWA) to facilitate injection of CO 2 for GS, while protecting human health and the environment by ensuring the protection of underground sources of drinking water (USDWs). The Class VI regulations are built upon 35 years of federal experience regulating underground injection wells, and many additional years of state UIC program expertise. The EPA and states have decades of UIC experience with the Class II program , which provides a regulatory framework for the protection of USDWs for CO 2 injected for purposes of EOR.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **368** of **763** In addition, to complement both the Class VI and Class II rules, the EPA used CAA authority to develop air
- side monitoring and reporting requirements for CO 2 capture, underground injection, and geologic sequestration through the GHGRP. Information collected under the GHGRP provides a transparent means for the EPA and the public to continue to evaluate the effectiveness of GS. As explained below, these requirements help ensure that sequestered CO 2 will remain in place, and , using SDWA and CAA authorities, provide the monitoring mechanisms to identify and address potential leakage . We note the near consensus in the public responses to the Class VI rulemaking that saline and oil and gas reservoirs provide ready means for secure GS of CO 2 . 414 1. Requirements for UIC Class VI and Class II Wells Under SDWA , the EPA developed the UIC Program to regulate the underground injection of fluids in a manner that 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 and gas

414 “Most commenters encourage d EPA not to automatically exclude any potential injection formations for GS at this stage of deployment. Commenters suggested, in particular, that there is sufficient technical basis and scientific evidence to allow GS in depleted oil and gas reservoirs and in saline formations, noting that there is consensus on how to inject into these formation types.” 75 FR at 77252 (Dec. 10, 2010).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **369** of **763** activities; solution mining fluids; and CO 2 for geologic sequestration) and which accommodate varying geologic, hydrogeological, and other conditions. The standards apply to injection into any type of formation that meets the rule’s rigorous criteria, and so apply not only to injection into deep 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 aquifers that contain a sufficient quantity of ground water to supply a public water system, where formation fluids either are currently being used for human consumption or that cont ain less than 10,000 ppm total dissolved solids. 415 UIC requirements have been in place for over three decades and have been used by the EPA 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, Class 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

415 40 CFR §144.3.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **370** of **763** GS including the large CO 2 injection volumes anticipated at GS projects, relative buoyancy of CO 2 , its mobility within subsurface geologic formations, and it s corrosivity in the presence of water. The UIC Class VI rule was developed to facilitate GS and ensure protection of USDWs from the particular risks that may be posed by large scale CO 2 injection for purposes of long- term GS . The Class VI rule establishes technical requirements for the permitting, geologic site characterization, area of review (i.e., the project area) and corrective action, well construction, operation, mechanical integrity testing, monitoring, well plugging, post
- injection site care, site closure, and financial responsibility for the purpose of protecting USDWs. 416 Notably:

416 The Class VI rule rests on a robust technical and scientific foundation, reflecting scientific oversight and peer review. In developing these Class VI rules, the EPA engaged with the SAB, providing detailed information on key issues relating to geologic sequestration

– including monitoring schemes; methods to predict and verify capacity, injectivity, and effectiveness o f 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/AD09B42B75D9E36D852 57704004882CF?OpenDocument . In addition, E PA developed a peer reviewed Vulnerability Evaluation Framework, which served as a technical support document for both the Class VI and Subpart RR rules. See: http://www.epa.gov/climatechange/Downloads/ghgemissions/VEF
Technical_Document_072 408.pdf . In the section 111 (b) rulemaking***EO 12866_Review
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 Site characterization includes assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of a proposed GS site to ensure that Class VI wells are sited in appropriate locations and CO 2 streams are inject ed into suitable formations with a confining zone or zones free of transmissive faults or fractures to ensure USDW protection. 417 , 418 Site characterization is designed to eliminate unacceptable sites that may pose risks to USDWs. Generally, injection of CO 2 for GS should occur beneath the lowermost formation containing a USDW. 419 To increase the availability of Class VI sites in geographi c areas with very deep USDWs, waivers from the injection depth

here, the SAB Work Group, in a letter endorsed by the full SAB Committee, found that “while the scientific and technical basis for carbon storage provisions is new and emerging science, the agency is using the bes t 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 Members of the Chartered SAB and SAB Liaisons, p. 3. The letter was subsequently endorsed by the full SAB. Work Group Letter of Jan. 24, 2014, as edited by the full Committee. 417 75 FR 77240 and 75 FR 77247 (December 10, 2010). 418 40 CFR §146.82 and §146. 83. Comments indicating that EPA rules have not considered issues of exposure pathways such as abandoned wells or formation fissures are mistaken. (See, e.g., Comments of UARG, p. 52 . ) 419 40 CFR §146.81(d).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **372** of **763** requirements may be sought where owners or operators can demonstrate USDW protection. 420

 Owners or operators of Class VI wells must delineate the project area of review using computational modeli ng that accounts for the physical and chemical properties of the injected CO 2 and displaced fluids and is based on an iterative process of available site characterization, monitoring, and operational data. 421 Within the area of review, owners or operators mu st identify and evaluate all artificial penetrations to identify those that need corrective action to prevent the movement of CO 2 or other fluids into or between USDWs. 422 , 423 Due to the potential ly large size of the area of review for Class VI wells, corrective actions may be conducted on a phased basis during the lifetime of the project. 424 Periodic reevaluation of the area of review is required and enables owners or operators to incorporate previous ly collected monitoring and operational data to verify that the CO 2 plume and the

420 40 CFR §146.95. 421 40 CFR §146.84(a). 422 40 CFR §146.84(c)(1)(3) and §146.90(d)(1). 423 40 CFR §146.81(d) and §146.84. 424 40 CFR §146.84(b)(2)(iv).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **373** of **763** associated area of elevated pressure are moving as predicted within the subsurface. 425

 Well construction must use materials that can withstand contact with CO 2 over the operati onal and post - injection life of the project. 426 These requirements address the unique physical characteristics of CO 2 , including its buoyancy relative to other fluids in the subsurface and its potential corrosivity in the presence of water.

 Requirements for operation of Class VI injection wells account for the unique conditions that will occur during large - scale GS including buoyancy, corrosivity, and high sustained pressures over long periods of operation. 427 , 428

 Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall
- off testing, CO 2 plume and pressure front monitoring and tracking, and, at the

425 40 CFR § 146.84(e)(1). 426 40 CFR §146.86(b). 427 75 FR 77250
- 52 (December 10, 2010) ; see also id. at 77234
- 35. Commenters were mistaken in asserting (without reference to Class VI provisions) that the EPA had ignored issues relating to CO 2 properties when injected in large volumes in supercritical state into geologic formations . 428 40 CFR §146.88.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **374** of **763** discretion of the Class VI director , surface air and/or soil gas monitoring. 429 Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the mo st recent area of review reevaluation. 430 Robust monitoring of the CO 2 stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO 2 plume and position of the pressure front throughout injection will ensure protection of USDWs from endangerment, preserve water quality, and allow for timely detection of any leakage of CO 2 or displaced formation fluids.

 Although subsurface monitoring is the primary and effective means of determining if there are any risks to a USDW, the Class VI rule also authorizes the UIC Program Director to require surface air and/or soil gas monitoring on a site
specific basis. For example, the Class VI Director may require surface 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. 431

429 40 CFR §146.90. 430 40 CFR §146.90(j). 431 40 CFR §146.90(h) ( 1) and 75 FR at 77259 (Dec. 10, 2010).***EO 12866_Review
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 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., cease injection) to address potential events that may cause endangerment to a USDW during the construction, operation, and post - injection site care periods of the project. 432

 Financial responsibility demonstrat ions are required to ensure that funds will be available for all area of review corrective action, injection well plugging, post
- injection site care, site closure, and emergency and remedial response. 433

 Following cessation of injection, the operator must conduct comprehensive post
- injection site care activities to show the position of the CO 2 plume and the associated area of elevated pressure to demonstrate that neither poses an endangerment to USDWs. 434 The injection well also must be plugged, and following a demonstration of non
- endangerment of USDWs by the Class VI owner or operator, the site must be closed. 435 , 436 The default duration for the post
- injection site care period is 50 years, with flexibility for

432 40 CFR §146.94. 433 40 CFR §146.85. 434 40 CFR §146.93. 435 40 CFR §146.9 2 . 436 40 CFR §146.93.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **376** of **763** demonstrating that an alternative period is appropriat e if it ensures non
- endangerment of USDWs. 437 Following successful closure, the facility property deed must record that the underlying land is used for GS. 438 The EPA has completed technical guidance documents on Class VI well site characterization, area of review and corrective action, well testing and monitoring, project plan development, well construction, and financial responsibility. 439 , 440 , 441 , 442 , 443 , 444 The EPA has also issued guidance documents on transitioning Class II wells to Class VI wells; well plugging, post
- injection

437 40 CFR §146.93(b). 438 40 CFR §146.93(c). 439 http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1 3004.pdf. 440 http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1 3005.pdf. 441 http://water.epa.gov/type/groundwater/uic/c lass6/upload/epa816r1 3001.pdf. 442 http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1 1017.pdf. 443 http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1 1020.pdf. 444 http://water.epa.gov/type/groundwater/uic/class6/upload/uicfinan cialresponsibilityguidancefinal072011v.pdf.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **377** of **763** site care, and site closure; and recordkeeping, reporting, and data management. 445 , 446 , 447 , 448 To inform the development of the UIC Class VI rule, the EPA solicited stakeholder input and reviewed ongoing domestic and international GS research, demonstration, and deployment projects. The EPA also leveraged injection experience of the UIC Program, such as injection via Class II wells for EOR. A description of the work conducted by the EPA in support of the UIC Class VI rule can be found in the preamble for the final rule (see 75 FR 77230 and 77237
- 240 ( December 10, 2010) ) . The EPA has issued Class VI permits for six wells under two projects. In September 2014, a UIC Cla ss VI injection well permit (to construct) was issued by the EPA to Archer Daniels Midland for an ethanol facility in Decatur, Illinois. The goal

445 http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1 3004.pdf. See also 40 CFR §144.19 and “Key Principles in EPA’s Underground Injection Control Program Class VI Rule Related to Transition of Class II Enhanced Oil Recovery or Gas Recovery Wells to Class VI”, April 23, 2015, Available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eo rclass6memo.pdf. 446 http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1 3005.pdf . 447 http://water. epa.gov/type/groundwater/uic/class6/upload/epa816p1 3001.pdf . 448 http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1 3002.pdf .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **378** of **763** of the project is to demonstrate the ability of the Mount Simon geologic formation , a deep saline formation, to accept and retain industrial scale volumes of CO 2 for permanent GS. The permitted well has a projected operational period of 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 approximately 2 miles. 449 Following the operational period, Archer Daniels Midland plans a post - injection site care period of ten years. 450 In September 2014, the EPA also issued four Class VI injection well permits (to construct) to the FutureGen Industrial Alliance p roject in Jacksonville, Illinois, which proposed to capture CO 2 emissions from a coal - fired power plant in Meredosia, Illinois and transport the CO 2 by pipeline approximately 30 miles to the deep saline GS site. 451 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 years. 452

449 http://www.epa.gov/region5/water/uic/adm/ . In addition, Archer Daniels Midland received a UIC Class VI injection well permit for a second well in December 2014. Archer Daniels Midland had been injecting CO 2 at this well since 2011 under a UIC Class I pe rmit issued by the Illinois EPA. 450 http://www .epa.gov/region5/water/uic/adm/ . 451 After permit issuance, and for reasons unrelated to the permitting proceeding, DOE initiated a structured closeout of federal support for the FutureGen project in February 2015. However, these are still active Class VI pe rmits. 452 http://www.epa.gov/r5water/uic/futuregen/ .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **379** of **763** Both permit applicants addressed siting and operational aspects of GS (including issues relating to volumes of the CO 2 and nature of the CO 2 injectate), and include d 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 receive inject ed CO 2 in specified amounts without buildup of pressure which would create faults or fractures, and further, that monitoring provides early warning of any changes to groundwater or CO 2 leakage. 453 The permitting of these projects illustrates that permit applicants were able to address perceived challenges to issuance of Class VI permits. These permits demonstrate that these projects are capable of safely and s ecurely sequestering 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, boosting production efficiency by re
-pressurizing oil and gas reservoirs and increasing the mobility of oil. There are decades of industry experience in operating EOR projects. The
453 http://www.epa.gov/r5water/uic/futuregen / ; http://www.epa.gov/region5/water/uic/adm/ .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **380** of **763** CO 2 injection wells used for EOR are regulated through the UIC Class II program . 454 CO 2 storage associated with Class II wells is a common occurrence and CO 2 can be safely stored where injected through Class II -permitted wells for the purpose of enhanced oil
or gas - related recovery. UIC Class II regulations issued under s ection 142 1 of SDWA provide minimum federal requirements for site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), in jectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility, and reporting. Class II wells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that could l ead to loss of injectate and migration into USDWs. Section 1425 of SDWA allows states to demonstrate that their program is effective in preventing endangerment 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 suppliers in the United States. The final rules under 40 CFR part 60

454 40 CFR §144.6(b).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **381** of **763** specifically require that if an affected EGU captures CO 2 to meet the applicable emissions limit, the EGU must report in accordance with 40 CFR part 98 , subpart PP (Suppliers of Carbon Dioxide) and the captured CO 2 must be injected at a facility or facili ties that reports in accordance with 40 CFR part 98 , subpart RR (Geologic Sequestration of Carbon Dioxide). See § 60.5555( f) . Taken together, these requirements ensure that the amount of captured and sequestered CO 2 will be tracked as appropriate at project
- and national
- levels, and that the status of the CO 2 in its sequestration site will be monitored, including air
- side monitoring and reporting. Specifically, subpart PP provides requirements to account for CO 2 supplied to the economy. This subpart requires affected facilities with production process units that capture 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 report the mass of CO 2 captured and supplied to the economy. 455 CO 2 suppliers are required to report the annual quantity of CO 2 transferred offsite and its end use, including GS. 456 This rule finalizes amendments to subpart PP reporting requirements, specifically requiring that the following pieces
455 40 CFR §98.420(a)(1). 456 40 CFR §98.426.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **382** of **763** 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 mass of CO 2 transferred to, each GS site reporting under subpart RR. 457 As noted, this final rule also requires that any affected EGU unit that captures CO 2 to meet the applicable emissions limit must transfer the captured CO 2 to a facility that reports unde r GHGRP subpart RR. In order to provide clarity on this requirement, the EPA reworded the proposed language under § 60.5555( f ) to use the phrase “If your affected unit captures CO 2 ” in place of the phrase “If your affected unit employs geologic sequestration”. This revision is not a change from the EPA’s initial intent. Reporting under subpart RR is required for all facilities that have received a Class VI UIC permit for injection of CO 2 . 458 Subpart RR requires facilities meeting the source category 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 monitoring, reporting, and ver ification (MRV) plan; report the mass of CO 2 sequestered using a mass balance approach ; and report annual

457 40 CFR §98.426(h). 458 40 CFR §98.440.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **383** of **763** monitoring activities. 459 , 460 , 461 , 462 Although deep subsurface monitoring is the primary and effective means of determining if there are any leaks to a USDW, the monitoring employed under a subpart RR MRV Plan can be utilized , if required by the UIC Program Director , to further ensure protection of USDWs. 463 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. 464

 An identification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO 2 through these pathways. The monitoring program will be designed to address the risks identified. 465

 A strategy for detecting and quantifying any surface leakage of CO 2 in the event leakage occurs. Multiple monitoring methods and accounting techniques can be used to address changes in plume size and risks over time. 466

459 40 CFR §98.446. 460 40 CFR §98.448. 461 40 CFR §98.446(f)(9) and (10). 462 40 CFR §98.446(f)(12). 463 See 75 FR at 77263 (Dec. 10, 2010). 464 40 CFR §98.448(a)(1). 465 40 CFR §98.448(a)(2). 466 40 CFR §98.448(a)(3).***EO 12866_Review
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 An approach for establishing the expected baselines for monitoring CO 2 surface leakage. Baseline data represent pre - injection site conditions and are used to identify potential anomalies in monitoring data. 467

 A summary of considerati ons made to calculate site
specific variables for the mass balance equation. Site
specific vari ables 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. 468 Subpart RR provides a nationally consistent mass balance framework for reporting the mass of CO 2 that is sequestered. Certain monitoring and operational data for a GS site is required to be reported to the EPA annually. More information on the MRV plan and annual reporting is available in the subpart RR final rule (75 FR 75065; December 1, 2010) and its associated technical support document. 469 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

467 40 CFR §98.448(a)(4). 468 40 CFR §98.448(a)(5). 469 Te chnical Support Document: “General Technical Support Document for Injection and Geologic Sequestration of Carbon Dioxide: Subparts RR and UU” (Docket EPA

–HQ

–OAR

– 2009

– 0926), November 2010.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **385** of **7 63**  under subpart RR. 470 As explained below in S ection V. N .5.a, a Class II well’s UIC regulatory status does not change because it receives such CO 2 . Nor does it change by virtue of reporting under subpart RR. 3. UIC and GHGRP Rules Provide Assurance to P revent , Monitor , and Address Releases of S equestered CO 2 to Air Together the requirements of the UIC and GHGRP programs help ensure that sequestered CO 2 will remain secure, and provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities. The EPA designed the GHGRP subpart RR requirements for GS with consideration of UIC requirements. The monitoring required b y GHGRP subpart RR is complementary to and builds on UIC monitoring and testing requirements. 75 FR 77263. Although the regulations for Class VI 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 understanding of the mechanisms by which CO 2 is retained in geologic formations, which are well understood and proven.

470 See §60.5555(f).***EO 12866_Review
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 Structural and stratigraphic trapping is a physical trapping mechanism that occurs when the CO 2 reaches a stratigraphic zone with low permeability (i.e., geologic confining system) that prevents further upward migration.

 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 edge of the plume due to capillary forces.

 Adsorption trapping is another physical trapping mechanism that occurs when CO 2 molecules attach to the surfaces of coal and certain organic rich shales, displacing other molecules such as methane.

 Solubility trapping is a geochemical trapping mechanism 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 mechanism that occurs when chemical reactions between the dissolved CO 2 and 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 VI rule provides a framework to ensure the safety of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **387** of **763** underground injection of CO 2 such that USDWs are not endangered. As explained below, protection against releases to USDWs likewise assures against releases to ambient air. Through the injection well permit application process , the Class VI permit applicant (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 injection zone or the approved project area (i.e., the area of review). To assure that CO 2 is confined within the injection zone, major components to be considered and included in Class VI permits are site characterization, area of review delineation and corrective action, well construction and operation, testing and 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 the chemical and physical mechanisms that will occur in the subsurface to immobilize and securely store the CO 2 within the injection zone over the long- term (see above) . Site characterization requires a detailed assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **388** of **763** that wells are sited in suitable locations. 471 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 the injected CO 2 plume and related pressure front; and establish baseline 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 monitoring requirements to assure that the chosen site is functioning as characterized. This subsurface monitoring should detect 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 detec ted by a UIC Class VI monitoring program that is approved and periodically evaluated/adjusted based on permit conditions. Likewise, UIC Class VI mechanical integrity testing requirements are designed to confirm that a well maintains internal and external mechanical integrity. Continuous

471 40 CFR §146.82(a) and (c).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **389** of **763** monitoring of the internal mechanical integrity of Class VI well s ensure s that injection wells maintain integrity and serves
as a way to detect problems with the well system. Mechanical integrity testing provides an early i ndication of potential 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 requirement that injection must cease if there is evidence that the injected CO 2 and/or associated pressure front may cause endangerment to a USDW. 472 Once the anomalous operating conditions are verified, the cessation of injection, as required by UIC permits, will minimize any risk of release to a ir. 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 USDWs

– also having the practical effect of preventing releases of CO 2 to the atmosphere . Post - injection site care includes appropriate monitoring and other needed actions (including corrective action). The default duration for the post
- injection site care period is 50 ye ars, with flexibility for demonstrating that an

472 40 CFR § 146.94(b)***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **390** of **763** alternative period is appropriate if it ensures non
- endangerment of USDWs. As the EPA has found, the UIC Class VI injection well requirements protect against releases from all exposure pathways . Specifically, EPA stated that the Class VI rules “[ are ] specifically designed to ensure that the CO 2 ( and any incidental associated substances derived from the source materials and the capture process) will be isolated within the injection zone. The EPA concluded that the elimination of exposure routes through these requirements , which are implemented through a SDWA UIC permit, will ensure protection of human health and the environment .. .” . 473 GHGRP subpart RR complements these UIC Class VI requirements. Requirements under the UIC program are focused on demonstrating that USDWs are not endangered as a result of CO 2 injection into the subsurface, while requirements under the GHGRP through subpart RR enable accounting for CO 2 that is geologically sequestered. A methodology to account for potential leakage is developed as part of the subpart RR MRV plan (see Section V. N .2) . The MRV plan submitted for subpart RR may describe (or provide by reference to the UIC permit) the
473 79 FR at 353 ( January 3, 2014 ) (Final Hazardous Waste Management System: Conditional Exclusion for Carbon Dioxide (CO 2 ) Streams in Geologic Sequestration Activities under subtitle C of RCRA ). See S ection N .5. c below.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **391** of **763** relevant elements of the UIC permit (e.g. assessment of leakage pathways in the monitoring area) and how those elements satisfy the subpart RR requirements. The MRV plan required under subpart RR may rely upon the knowledge of the subsurface location of CO 2 and site characteristics that are developed in the permit application process , and operational monitoring results for UIC Class VI permitted wells. In summary, there are well - recognized physical mechanisms 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. Subsurface monitoring serves to assure that the sequestration site operates as intended, and this monitoring continues through a post
- 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 provides backup
assurance that sequestered CO 2 has not been released to the atmosphere . b. Class II wells . The Class II rules likewise are designed to protect USDWs during EOR operation, including the injection of CO 2 for EOR. For example, UIC Class II minimum federal requirements promulgated under SDWA address site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **392** of **763** pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility, and reporting. Class II wells must undergo peri odic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss of injectate and migration into USDWs. The establishment of maximum injection pressures, designed to ensure that the pressure in the in jection zone during injection does not initiate new fractures or propagate existing fractures in the confining zone , prevents injection from causing the movement of fluids into an underground source of drinking water. The safeguards that protect USDWs also serve as an early warning mechanism for releases of CO 2 to the atmosphere . CO 2 injected via Class II wells become s 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 after the injection period. Subpart RR provides a CO 2 accounting framework that wi ll enable EPA to assess both the project
- level and national efficacy of geologic sequestration to determine whether additional requirements are necessary and, if so, inform the design of such regulations.***EO 12866_Review
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c. Response to Comments . Commenters maintained that GS was not demonstrated for CO 2 captured from EGUs. In addition, commenters noted that the volumes of captured CO 2 would be considerably larger than from existing GS sites, and could quadruple amounts injected 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. 474 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 regulatory impact analysis for this rule relies on GS in deep saline formations . 475 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, approximately 60 million metric tons of CO 2 were supplied to EOR in the United
474 See, e.g. Comments of Southern Company, p. 41. 475 The EPA anticipates EOR projects may be early GS projects because these formations have been previously well characterized for hydrocarbon recovery, likely already have suitable infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of oil production.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **394** of **763** States in 2013. 476 Approximat ely 70 percent of total CO 2 supplied in the United States was produced from geologic (natural) CO 2 sources and approximately 30 percent was captured from anthropogenic sources. CO 2 pipeline systems, such as those serving the Permian Basin, have multiple sources of CO 2 that serve to levelize the pipeline supply , thus minimizing the effect of supply on the EOR operator. GS of anthropogenic CO 2 in deep saline formations is demonstrate d. First, as explained above, the EPA has 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 wa s for a steam generating EGU. Second , international experience with large scale commercial GS projects has demonstrated through extensive 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 under this rule. This experience has also demonstrated the value and efficacy of monitoring programs to determine the location of CO 2 in the subsurface and detect potential leakage through the presence of CO 2 in the shallow subsurface, near surface and air.
476 Greenhouse Gas Reporting Program, data reported as of August 18, 201 4 .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **395** of **763** 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. Approximately 15 million metric tons of CO 2 have been injected since inception. Many US and international organizations have conducted monitoring at Sleipner. The location and dimensions of the CO 2 p lume have been measured numerous times using 3
- dimensional seismic monitoring since the 1994 pre
- injection survey . The monitoring data have demonstrated that although the plume is behaving differently than initially modeled due to thin layers of impermeabl e shale that were not initially identified in the reservoir model, the CO 2 remains trapped in the injection zone. Numerous other techniques have been successfully used to monitor CO 2 storage at Sleipner. The research and monitoring at Sleipner demonstrates the value of a comprehensive approach to site characterization, computational modeling and monitoring, as is required under UIC Class VI rules. The experience at Sleipner demonstrates that large volumes of CO 2 , of the same order of magnitude expected for an EGU, can be safely injected and stored in saline reservoirs over an extended period.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **396** of **763** Snøhvit is another large offshore CO 2 storage project, located at a gas field in the Barents Sea. Like Sleipner the natural gas must be treated to reduce high levels of CO 2 to meet processing standards and reduce costs. Gas is transported 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. Between 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 increase was mainly caused by a limited storage capacity in the formation. 477 In 2011, the injection well was modified and injection was initiated in a second interval (Stø Formation) in the field to increase the storage capacity. Approximately 3 million metric tons of CO 2 have been injected since 2008. Monitoring demonstrates that no leakage has occurred, again demonstrating that large volumes of CO 2 , of the same order of magnitude

477 Grude, S. M. Landrøa, and J. Dvorkinb, 2014, Pressure 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
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– Do Not Cite, Quote or Release During Review *** Page **397** of **763** expected for an EGU, can be sa fely injected and stored in deep saline formations over an extended period. As discussed above in s ection s V.E.2.a and M , CO 2 from the Great Plains Synfuels plant in North Dakota has been injected into the Weyburn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO 2 . It is anticipated that approximate ly 40 million metric tons of CO 2 will be permanently sequestered over the lifespan of the project. Extensive monitoring 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 not impact the effectiveness of EOR operation s (see Section V.M . 3 ). CO 2 used for EOR may come from anthropogenic or natural 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 Transportati on Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation 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 transport companies have specifications to ensure related to the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **398** of **763** 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 gas fields in order to meet export quality specification. The CO 2 is transported by pipeline approximately 3 miles to the injection site. Three horizontal wells are used to inject the CO 2 into the down - dip aquifer leg of the gas reservoir approximately 6 , 200 feet deep. Between 2004 and 2011 over 3.8 million metric tons of CO 2 were stored. Injection rates in 2010 and 2011 were approximately 1 million metric tons per year. Storage integrity has been monitored by several US and international organizations and the monitoring program has employed a wide range of geophysical and geochemical methods, including time lapse seismic, microseismic, wellhead sampling, tracers, down -hole logging, core analysis, surface gas monitoring, groundwater aquifer monitoring and satellite data. The data have been used to support periodic risk assessments during the operational phase of the project. In 2010 new data from seismic, sat ellite and geomechanical models were used to inform the risk assessment and led to the decision to reduce CO 2 injection pressures due to risk of vertical leakage into the lower caprock, and risk of loss of well integrity. The caprock at the site consisted of main caprock units, providing the primary seal, and lower***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **399** of **763** caprock units, providing additional buffers. There was no leakage from the well or through the caprock, but the risk analysis identified an increased risk of leakage, therefore, the aforementione d precautions were taken. Additional analysis of the reservoir, seismic and geomechanical data led to 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 shutdown of injection resulted from the analysis of seismic and geomechanical data to identify and respond to storage site risk. The In Salah project demonstrates the value of developing an integrated and comprehensive set of baseline sit e data prior to the start of injection, and the importance of regular review of monitoring data. Commenters also noted that the data collection and analysis had proven effective at preventing any release of sequestered CO 2 to either underground drinking water sources or to the atmosphere . 478 These projects demonstrate that sequestration of CO 2 captured from industrial operations has been successfully

478 “It is important to note that although the In Salah project is no longer injecting CO 2 , the CCS community still views this early saline project as a success because the monitoring program served its intended purpose. That is, the monitoring methods deployed at this site informed the operator of a potential problem, leading to a shutdown of CO 2 injection before the Caprock was breached.” Comment of EPRI, p. 14.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **400** of **763** 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 potentially 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 evaluated on a
case -by- case basis to select a site where the geologic conditions are suitable to ensure long
- term , safe storage of CO 2 . Each project was designed to address the site
- specific characteristics and operated to successfully inject CO 2 for safe storage. 4 . Must the s tandard of performance for CO 2 i nclude CAA
requirements on the s equestration s ite? One commenter maintained as a matter of law that a standard predicated on use of CCS is not a “system of emission reduction”, and therefore is not a “standard of performance” within the meaning of section 111 (a)(1) of the Act. The 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 standard. A gloss on this argument is that there are no enforceable requirements for the captured CO 2 (“[t]he fate of that [captured] CO 2 is something***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **401** of **763** 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 “designed 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). 479 The EPA disagrees with both the legal and factual
a ssertions in this comment . As to the legal point, the commenter fails to distinguish capture and sequestration of carbon from every other section 111 standard which is predicated on capture of a pollutant. Indeed, all emission standards not predicated on outright pollutant destruction involve capture of the pollutant and its subsequent disposition in the capturing medium. Thus, metals are captured in devices like baghouses or scrubbers, leaving a solid waste or wastewater to be managed. Gases can be captured with activated carbon or under pressure, again requiring further management of the captured pollutant(s). The EPA is required to consider these potential implications in promulgating an NSPS. See section 111(a)(1) (in promulgating a standard of performance under section 111, the EPA must “tak[e] into account ... any nonair qua lity health and environmental

479 Comments of UARG, pp. 37, 38.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **402** of **763** impact”). The EPA thus considers such issues as solid waste and wastewater generation as part of determining if a system of emission reduction is “best” and “adequately demonstrated” under section 111. See section V.O below (discussion of this rule’s potential cross
-media impacts). The further comment that the standard is arbitrary because it fails to impose any requirements on the captured CO 2 is misplaced. The commenter mischaracterizes the standard as requiring capture only. The BSER is not just capturing a certain amount of CO 2 , but sequestering it. Sequestration can occur either on
- site or off
- site. Sequestration sites receiving and injecti ng the captured CO 2 are required to obtain UIC permits and report under subpart RR of the GHGRP . They must conduct comprehensive monitoring as part of these obligation s . Although the NSPS does not impose regulatory requirements on the transportation pipeli ne or the sequestration site, such requirements already exist under other regulatory programs of the Department of Transportation and the EPA. In particular, the EPA is reasonably relying on the already
- adopted, and very rigorous, Class VI well requirement s in combination with the subpart RR requirements to provide secure sequestration 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **403** of **763** requirements, ensure protection of USDWs from endangerment , provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities, and 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 air pollution control residue to be disposed of pursuant to waste management requirements of the rules implementing the Resource Conservation and Rec overy Act, and the many section 111 standards of performance for metals or organics captured in wet air pollution control systems resulting in wastewater discharged to a navigable water where pollutant loadings are controlled under rules implementing the C lean Water Act. Again, these are non
- air environmental impacts for which the EPA must account in establishing a section 111(a) standard. The EPA has reasonably done so here based on the regulatory regimes of the Class VI and Class II UIC requirements in combination with the monitoring regime of the subpart RR reporting rules, as well as the CO 2 pipeline standards of the Department of Transportation. In this regard, the EPA notes that at proposal it acknowledged the possibility “that there can be downstream losses of CO 2 after capture, for example during transportation, injection or storage.” 79 FR at 1484. Given the rigorous substantive requirements and the monitoring required by the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **404** of **763** 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 such losses would be de minimis. Indeed, the same commenter maintained that the monitoring requirements of the Class VI rule are overly stringent and that a 50
- year po st - injection site care period is unnecessarily long. 480 As it happens, as noted above, the Class VI rules allow for an alternative post
- injection site care period based on a site
- specific demonstration. See 40 CFR 146.93(b). The EPA addresses this comment in more detail in Chapter 2 of the Response - to - Comment Document. 5 . Other Perceived Obstacles to Geologic Sequestration
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 transition to Class VI wells if they inject anthropogenic CO 2 , and further maintained that, as a practical matter, this would render EOR unavailable for such CO 2 . The EPA disagree s with these comment s . Injection of anthropogenic CO 2 into Class II wells does not force transition of these wells to Class VI wells

– not during the well’s active operation and not when EOR operations cease. We recognize the widespread use of

480 Comments of UARG, p. 63.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **405** of **763** EOR and the expectation that injected CO 2 can remain underground. The EPA issued a memorandum to its regional offices on April 23, 2015 reflecting these principles: 481

 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 production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted EOR operation, the key factor in determining the potential need to transition an EOR operation from Class II to Class VI is increased risk to USDWs related to significant storage of CO 2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. 482

481 “Key P rinciples 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/upload/class2e o rclass6memo.pdf 482 In this regard, the Class VI rules provide that, “[o]wners or operators that are injecting carbon dioxide for the primary***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **406** of **763** b. GHGRP Subpart RR . A number of commenter s maintained that no EOR operator would accept captured carbon from an EGU due to the reporting and other regulatory burdens imposed by the monitoring requirements of GHGRP subpart RR. 483 They noted that preparing a subpart RR MRV plan could cost upwards of $100,000 which would be cost prohibitive given other available sources of CO 2 . The EPA disagrees with this comment in several respects. First, the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. However , the EPA also recognizes the potential for sequestering CO 2 via EOR , but disagrees that subpart RR requirements effectively preclude or substantially inhibit the use of EOR . The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relatively modest , especially in comparison with revenue s from an EOR field . In the economic impact analysis for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and purpose of long- term storage into an oil and gas reservoir must apply for and obtain a Class VI geologic sequestrat ion permit when there is an increased risk to USDWs compared to Class II operations.” 40 CFR § 144.19. 483 See e.g., comments of UARG , p, 63 ; Southern Co., p. 37 ; American Petroleum Institute pp. 40
- 50.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **407** of **763** an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year. 484 Monitoring costs are estimated to range from $0.02 per metric ton (base case scenario) to approximately $2 per metric ton of CO 2 (high scenario) . Using a range of scenarios (that included high end estimates), these s ubpart RR costs are approximately three to four percent of estimated revenues for an average EOR field, indicating that the costs can readily 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 development of EOR will need to rely on captured CO 2 . 485 Thus, the argument that EOR operators will obtain CO 2 from other sources wi thout triggering subpart RR responsibilities , which assumes adequate supplies of CO 2 from other sources, lacks foundation. In addition, the Internal Revenue Code section 45Q provides a tax credit for CO 2 sequestration which is far greater than subpart RR costs . 486 In

484 Subpart RR costs are presented in 2008 US dollars. 485 “Near Term Projections of CO 2 Utilization for Enhanced Oil Recovery”. DOE/NETL
- 2014/1648. April 2014. 486 http://www.irs.gov/irb/2009
- 44_IRB/ar11.html. The section 45Q tax credit for calendar year 2015 is $10.92 per metric 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
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– Do Not Cite, Quote or Release During Review *** Page **408** of **763** sum, the cost of complying with subpart RR requirements, including the cost of MRV, is not significant enough 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 CO 2 streams under the Resource Conservation and Recovery Act (RCRA) . Certain commenters voiced concerns that regulatory requirements for hazardous wastes might apply to captured CO 2 and these requirements might be inconsistent with, or otherwise impede, GS of captured CO 2 from EGUs. The EPA has acted to remove any such (h ighly conjectural) uncertainty. The Resource Conservation and Recovery Act (RCRA) authorizes the EPA to regulate the management of hazardous wastes. In particular, RCRA Subtitle C authorizes a cradle to grave regulatory program for wastes identified as haz ardous, whether specifically listed as hazardous or whether the waste fails certain tests of hazardous characteristics. The EPA currently has little information to conclude that CO 2 streams (defined in the RCRA exclusion rule as including incidental associ ated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process) might be identified as “hazardous wastes” subject to RCRA***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **409** of **763** Subtitle C regulation. 487 Nevertheless, to reduce potential uncertainty regarding the regulatory status of CO 2 streams under RCRA Subtitle C, and in order to facilitate the deployment of geologic sequestration, the EPA recently concluded a rulemaking to exclude certain CO 2 streams from the RCRA de finition of hazardous waste. 488 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 and the environment provided certain conditions are met. Specificall y, the rule conditionally excludes from Subtitle C regulations CO 2 streams if they are (1) transported in compliance with U.S. Department of Transportation or state requirements; (2) injected in compliance with UIC Class VI requirements (summarized above); (3) no other hazardous wastes are mixed with or co
- injected with the CO 2 stream; and (4) generators (e.g., emission sources) and Class VI well owners or operators sign certification statements. See 40 CFR 261.4(h)). 489 The D.C. Circuit recently dismissed al l

487 No hazardous waste listings apply to CO 2 streams. Therefore, a CO 2 stream could be identified (i.e. defined ) as a hazardous waste only if it exhibits one or more of the hazardous characteristics. 79 FR 355 (Jan 3. 2014). 488 79 FR 350 (Jan. 3, 2014). 489 The EPA made clear in the final conditional exclusion 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 in the preamble to the final rule that (based on the limited informat ion provided in public comments) should CO 2 be used for***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **410** of **763** 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 uncertainties preclude a finding that geologic sequestration of CO 2 from EGUs can be considered to be adequately demonstrated. Many of the issues referred to in comments relate to property rights: issues of ownership of pore space, relationship of sequestration to ownership of mineral rights, issues of dealing with multiple landowners, lack of state law frameworks, or competing, inconsistent state laws. 490 Other commenters noted the lack of long- term liability ins urance, and noted uncertainties regarding long
- term liability generally . 491
its intended purpose as it is injected into UIC Class 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 activity. 79 FR 355. The EPA encouraged persons to consult with the appropriate regulatory authority to address any fact
- specific questions that they may have regarding the status of 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 waste 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. 490 See e.g. Comments of Duke Energy , p. 28; UARG , p. 62; AEP , p. 91. 491 See e.g. Comments of UARG, pp. 26, 62; EEI, p. 92; Duke Energy, pp. 27, 28.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **411** of **763** 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 methods, the risks of GS would be comparable to risks of current activities , such as EOR, acid gas injection and underground natural gas storage . 492 Furthermore, an interagency CCS task force examined GS - related legal issues thoroughly and concluded that early CCS projects can proceed under the existing legal framework with respect to issues such as property rights and liability. 493 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 fact that these applicants pursued permits indicates that they regarded any potential property rights issues as resolvable. Commenter American Electric Power ( AEP) referred to its own experience with the Mountaineer demonstration project. AEP noted that although this project was not full scale, finding a suitable repository, notwithstanding a generally favorable geologic area, proved difficult. The company refer red to years

492 Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide Capture and Storage. 493 http://www.epa.gov/climatechange/Downloads/ccs/CCS
- TaskForce -Report - 2010.pdf***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **412** of **763** spent in site characterization and digging multiple wells. 494 Other commenters noted more generally that site characterization issues can be time
- consuming and difficult, and quoted studies suggesting that it could take 5 years to obtain a Class VI permit. 495 The EPA agrees that robust site characterization and selection is important to ensuring capacity needs are met and that the sequestered CO 2 is safely s tored. Efforts to characterize geologic formations suitable for GS have been underway at DOE through the RCSPs since 2003 (see Section V. M ). Additionally, since 2007, the USGS has been assessing U . S . geologic storage resources for CO 2 . As noted earlier, DOE, i n partnership with researchers, universities, and organizations across the country, is demonstrating that GS can be achieved safely, permanently, and economically at large scales , and projects supported by the department have safely and permanently stored 10 million metric tons of CO 2 . In the time since the commenter submitted comments s everal Class VI permits have been issued by the EPA. These projects demonstrate that a GS site permit applicant could potentially prepare and obtain a UIC permit concurrent with permits required

494 AEP Comments at pp. 93, 96. 495 See e.g. Comments of UARG, p. 55, ci ting to Cichanowitz CCS Report (2012).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **413** of **763** for an EGU. With respect to AEP’s experience with the 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 explained how. 496 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 appropriate to generalize from AEP’s experience, and assume that other sites will require the same number of wells for site characterization or injection. In this regard, we note that the ADM and FutureGen construction permits for Class VI wells involved far fewer injection wells than AEP references. 497 See also discussion of this issue in section V.I.5 above.

496 See AEP FEED Study at pp. 36
- 43. The company likewise explained the monitoring regime it would utilize to verify containment, and the well construction it would utilize to guarantee secure sequestration. Id. at pp. 44 - 54. Available at: www.globalccsinstitute.com/publications/aep
-mountaineer
- ii
project
- front - end- engineering
- and- design
- feed- report 497 The FutureGen UIC Class VI injection we ll permits (four in total) require nine monitoring wells. http://www.epa.gov/r5water/uic/futuregen/ . The Archer Daniels Midland UIC Class VI injection well permit issued in September 2014 (CCS2) requires five monitoring wells and the Archer Daniels Midland UIC Class VI injection well permit is sued in***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **414** of **763** O . Nonair Quality Impacts and Energy Requirements As part of the determination that SCPC with partial CCS is the best system of emission reduction adequately demonstrated, the EPA has given careful consideration to nonair quality health and environmental impacts and energy requirements, as required by CAA section 111 (a). We have also considered those factors for alternative potential compliance paths to assure that the standard does not have unintended adverse health, environmental or energy- related consequences. The EPA finds that neither the BSER, nor the possible alternative compliance pathways, would have adverse consequences from either a nonair quality impact or energy requirement perspective. 1. Transport and Sequestration of Captured CO 2 As just discussed in detail, EPA finds that the Class VI and I I rules, as complemented by the subpart RR GHGRP reporting and monitoring requirements, amply safeguard against potential of injected CO 2 to degrade underground sources of drinking water and amply protect against any releases 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 release, and that these rules, plus the complementary tracking and reporting rules in subpart RR, assure December 2014 (CCS1) was permitted with two monitoring wells . http://www.epa.gov/region5/water/uic/adm/.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **415** of **763** 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 negative environmental impacts of the use of CCS for the mitigation of CO 2 emissions from fossil fuel
- fired st eam generating EGUs. In particular, commenters noted that the use of CCS will increase the water usage at units that implement CCS to meet the proposed standard of performance. At least one commenter claimed 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 and in the arid west and referenced a study in the scientific literature as support . 498 The commenter also references a DOE/NET L report that likewise notes significant increases in the amount of cooling and process water required with the use of carbon capture technology. 499 However, those studies discuss increased water use for cases where full CCS (90 percent or greater capture) is implemented. As we discussed in both the proposal and in this

498 See comments of UARG at p. 84 referencing Haibo Zhai, et al. , Water Use at Pulverized Coal Power Plants with Post
- combustion Carbon Capture and Storage, 45 Environ. Sci. Technol. , 2479
- 85 (2011) 499 Id at p. 84 referencing DOE/NETL
- 402/080108, “Water Requirements for Existing and Emerging Thermo electric Plant Technologies” at 13 (Aug. 2008, Apr. 2009 revision).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **416** of **763** preamble, the EPA does not find that highly efficient new generation technology implementing full CCS is the BSER for new steam generating EGUs. The EPA examined water use predicted from the updated DOE/NETL studies in order to determine the magnitude of increased water usage for a new SCPC implementing partial 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 SCPC unit that implements 16 percent partial CCS to meet the final standard would see an increase in water consumption (the difference between the predicted water withdraw and discharge) of about 6.4 percent compared to an SCPC with no CCS and the same net power output. By comparison, a unit implementing 35 percent CCS to meet the proposed emission limitation of 1,100 lb CO 2 /MWh
- g would see an increase in water consumption of 16.0 percent and a new unit implementing full (90 percent) CCS would see an increase of almost 50 percent. **Table 13**  **. Predicted Water Consumption with Implementation of**  **Various Levels of Partial CCS 500**  Raw Water Increase Compared

500 Exhibits A
- 1 and A
- 2 at p. 16
- 17 from “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal
- Fired Power Plants”, DOE/NETL
- 2015/1720 (June 22, 2015).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **417** of **763** 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 full CCS with net output of 543 MWe. The water consumption for each was normalized to 550 MWe to be consistent with the SPCP cases. Similar to other air pollution controls

– such as a wet flue gas desulfurization scrubber

– utilization of post
combustion amine
-based capture systems results in increased consumption of water. However, by finalizing a s tandard that is less stringent than the proposed limitation and by rejecting full CCS as the BSER, the EPA has reduced the increased amount of water needed as compared to a similar unit without CCS. Further, the EPA notes that there are additional opportunities to minimize the water usage at such a facility. For example, the SaskPower Boundary Dam Unit #3 post
- combustion capture project captures water from the coal and from the combustion process and recycles the captured water in the process, resu lting 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 is nearly 20***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **418** of **763** percent less than that predicted for the new SCPC unit without CCS (and almost 25 percent less than the SCPC unit meeting the final standard). The EPA rejected new IGCC implementing full CCS as BSER because the predicted costs were significantly more than alternative technologie s. The EPA also does not find that a new IGCC EGU is part of the final BSER (for reasons discussed in section V.P ). However, the EPA does note that IGCC is a viable alternative compliance option and, as shown here, would result in less water consumption than a compliant SCPC EGU. The EPA also notes that predicted water consumption at a new NGCC unit would be less than half that for a new SCPC EGU with the same net output. 501 3. Energy Requirements The EPA also examined the expected impacts on energy requirements for a new unit meeting the final promulgated standard and finds impacts to be minimal. Specifically , 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 DOE/NETL studies in order to determine the increased energy requirement for a new SCPC implementing partial CCS to meet the final

501 The EPA also finds that the standards would not re sult in any significant impact on solid waste generation or management. See section XI I I .D below.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **419** of **763** 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. **T able**  **14 .**  **Predicted Parasitic Power Demand with Implementation of Various Levels of Partial CCS**  **502** Generation Gross Power Auxiliary Parasitic Technology Output, MWe Power, MWe Demand (%) SCPC 580 30 5.2 SCPC + 16% CCS 599 38 6.3 SCPC + 35% CCS 603 53 8.8 SCPC + 90% CCS 642 91 14.2 IGCC 748 126 16.8 IGCC + 90% CCS 734 191 26.0 The auxiliary power demand is the amount of the gross power output that is utilized within the facility rather than used to produce electricity for sale to the grid. The parasitic power demand (or parasitic load) is the percentage of the gross power output that is needed to meet the auxiliary power demand. 503 In an SCPC EGU without CCS, the auxiliary power is used to primarily to operate fans, motors, pumps, etc. associated with

502 Exhibits A
- 1 and A
- 2 at p. 16
- 17 from “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivi ty to CO 2 Capture Rate in Coal
- Fired Power Plants”, DOE/NETL
- 2015/1720 (June 2015). 503 Note that this auxiliary power demand is not necessarily met from power or steam generated from the EGU. External sources can also be utilized for this purposes.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **420** of **763** operation of the facility and the associated pollution control equipment. When ca rbon capture equipment is incorporated, additional power is needed to operate associated equipment , and steam is need to regenerate the capture solvents (i.e., the solvents are heated to release the captured CO 2 ). The results in Table 14 show that a new SCPC unit without CCS can expect a parasitic power demand of about 5.2 percent. A new SCPC unit meeting the final standard of performance by implementing 16 percent partial CCS will see a parasitic power demand of about 6.3 percent, which is not a significant increa se in energy requirement. Of course, new SCPC EGUs that 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 generating 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. Progress is being made. As was mentioned previously, the heat duty (the energy required to regenerate the capture solvent) for the amine scrubbing process used at the Searles Valley facility in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **421** of **763** mid
- 70’s was about 12 MJ/mt CO 2 removed as compared to a heat duty of about 2.5 MJ/mt CO 2 removed for the amine processes used at Boundary Dam and for the amine system that will be used at the WA Parish facility. 504 The EPA also examined the predicted parasitic power demand for a new IGCC and for a new IGCC implementing 90 percent CCS. As we have noted elsewhere, the auxiliary power demand 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 unit implementing full CCS would expect a parasitic power demand of nearly 30 percent. Of course, the EPA rejected new IGCC implementing full CCS as BSER because of the potentially unreasonable costs. The EPA also does not find that a new IGCC EGU is part of the final BSER (for reasons discussed elsewhere in section V. P .1 below ). However, as we have noted, the EPA does find IGCC to be a viable alternative compliance option. Utilities and project developers should consider the increased auxiliary power demand for an IGCC when consider ing their options for new power generation. The EPA also notes that the predicted parasitic load for a new NGCC unit would be about 2
504 “From Lubbock, TX to Thompsons, TX - Amine Scrubbing 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 (October 2014).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **422** of **763** percent - less than half that for a new SCPC EGU with the same net output. 505 With respect to potential nationwide impacts on energy requirements, a s described above in secti on V. H.3 and more extensively in the RIA chapter 4 , EPA reasonably projects that
no new non - compliant fossil
- fuel fired steam electric capacity will be constructed through 2022 ( the end of the 8 year review cycle for NSPS). It is possible, as described earlier, that some new sources could be built to preserve fuel diversity, but even so, the number of such sources would be small and therefore would not significantly impact national energy requirements (assuming that such sou rces would not already be reflected in the baseline conditions just noted). P . Options That Were Considered by EPA but Were Ultimately Not Determined to Be the BSER In light of the comments received, the EPA re - examined several alternative systems of emission reduction and 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 emis sion

505 The EPA also finds that the standards would not result in any significant impact on solid waste generation or management. See section XII.D below.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **423** of **763** reduction options. These are described below. See also section IV.B.1 above . 1. Highly Efficient Generation Technology (e.g., Supercritical
or Ultra - supercritical Boilers ) In the January 2014 proposal, we considered whether ‘Highly Efficient New Generation without CCS Technology’ should constitute the BSER for new steam generating units. 79 FR at 1468
- 69. The discussion focused on the performance of highly efficient generat ion technology (that does not include any implementation of CCS), such as a supercritical 506 pulverized coal (SCPC) or a supercritical CFB boiler, or a modern, well
performing IGCC unit. All these options are technically feasible

– there are numerous example s 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:
a. Lack of significant CO 2 reductions when compared to business as usual . At the outset, we reviewed the emission rates of efficient PC and CFB units. According to the DOE/NETL estimates ,

506 Subcritical coal
- fired boilers are designed and operated with a steam cycle below the critical point of water. Super critical coal - fired boilers are designed and operated with a steam cycle above the critical point of water. Increasing the steam pressure and temperature increases the amount of energy within the steam, so that more energy can be extracted by the steam turbine, which in turn leads to increased efficiency and lower emissions.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **424** of **763** a newly constructed subcritical PC unit firing bituminous coal would emit approximately 1,800 lb CO 2 /MWh - g , 508 a new highly efficient SCPC unit using bituminous coal would emit nearly 1, 7 20 lb CO 2 /MWh - g , and a new IGCC unit would emit about 1, 4 30 lb CO 2 /MWh - g . 510 , 511 Emissions from comparable sources utilizing sub
bituminous coal or lignite will have somewhat higher CO 2 emissions. 512 Some commenters noted that new coal - fired plants utilizing supercritical boiler design or IGCC would provide substantial emission reductions compared to the emissions from the existing subcritical coal plants that are currently in wide use in the power sec tor. 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 constructed and those that have been proposed

– are supercritical boilers and IGCC

508 Exhibit ES
- 2 from “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL
- 2010/1397 (November 2010). 510 “ Cost and Performance Baseline for Fossil Energy Plants 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. 511 The comparable emissions on a net basis are: subcritical PC

– 1,8 90 lb CO 2 /MWh - n ; SC PC

– 1, 7 05 lb CO 2 /MWh - n ; and IGCC

– 1, 72 4 lb CO 2 /MWh - n . (See same references as for gross emissions provided in the text). 512 Exhibit ES
- 2 from “Cost and Performance Baseline for Fossil Energy Plants Volume 3b: Low Rank Coal to Electricity: Combustion Cases”, Report DOE/NETL
- 2010/ 1 463 ( March 2011 ) .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **425** of **763** units. About 60 percent of new coal - fired utility boiler capacity that has come on
- line since 2005 was supercritical and of the new capacity that came on - line since 2010, about 70 percent was supercritical. No new coal - fired utility boilers began operation in either 2013 o r 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
- supercritical 513 PC (USCPC) facility located in the southwest corner of Arkansas, and Duke Energy’s Edwardsport plant, which is a 618 MW “CCS ready” 514 IGCC unit located in Knox County, Indiana. Both of those facilities came on
- line in 2012. It is likely that the units that initiated operation in 2010 or later were conceived of, planned, designed, and permitted well before 2010

– likely in the early 2000s. Thus, it seems clear that the power sector had already , at that point , transitioned to the selection of supercritical boiler technology as “business as usual” for new coal - fired power plants. Since that time, there have been other coal - fired power plants that have been proposed and almost all of them have been either supercri tical boiler designs or IGCC units. In Table 1 of the Technical Support Document Fossil Fuel
- 513 Ultra - supercritical (USC) and advanced ultra
- supercritical (A-USC) are terms often used to designate a coal
- fired power plant design with steam conditions well above the critical point. 514 A “CCS ready” facility is one that is designed such that the CCS equipment can be more easily added at a later time.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **426** of **763** Fired Boiler and IGCC EGU Projects Under Development: Status and Approach 515 for the January 2014 proposal, the EPA listed the development status of “potential tran sitional sources” (i.e., projects that had been proposed and had received Prevention of Significant Deterioration (PSD) preconstruction permits as of April 13, 2012 ). Of the 16 proposed EGU projects in Table 1

– most of which have been cancelled or converted to or replaced with NGCC projects

– the majority (nine) are either supercritical PC or IGCC designs. Five of the proposed projects were CFB designs with only one being a subcritical PC design. The EPA is aware of only one new coal
- fired power plant that is actively in the construction phase. That plant is Mississippi Power’s Kemper County Energy Facility in Kemper County, MS

– an IGCC unit that plans to begin operations in 2016 and will implement partial CCS to capture approximately 65 percent of the available CO 2 , which will be sold for use in EOR operations. Considering the direction that the power sector has been taking and the changes that it is undergoing, identifying a new supercritical unit as the BSER and requiring an emission limitation based on the performance of such units thus would provide few, if any, additional CO 2 emission reductions beyond
515 Available in the rulemaking docket ID: EPA
- HQ - OAR- 2013
- 0495
- 0024.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **427** of **763** the sector’s “business as usual”. As noted, for the most part, new sources are already designed to achieve at least that emission limitation. This criterion does not itself eliminate supercritical technology from consideration as BSER. However, existing technologies must be considered in the context of the range of technically feasible technol ogies and, as we discuss elsewhere in this final preamble , partial CCS can achieve emission limitations beyond business a s usual and do 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 basis, have inherently lower CO 2 emission rate s when compared to similarly
sized SCPC units. However, the net emission rates and overall emissions to the atmosphere (i.e., tons of CO 2 per year) tend to be more similar (though still somewhat lower) for new IGCC units when compared to new SCPC units with the same electrical output. Therefore an emission limitation based on the expected performance of a new IGCC unit would result in some CO 2 emission reductions from the segment of the industry that would otherwise construct new PC units, but not from the segment of the industry that would already construct new IGCC units. A gross
- output based emission limitation consistent with the expected performance of a new IGCC unit would still require some***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **428** of **763** additional control, such as partial CCS, on a new supercritical boiler. As is shown in S ection V.J and H , additional emission reductions beyond those that would result from an emission standard based on a new SCPC boiler or even a new IGCC unit as the BSER can be achieved at a reasonable cost. Because practicable emission controls are available that are of
re asonable cost at the source level and that will have little cost and energy impact at the national level , the EPA is according significant weight to the factor of amount of emissions reductions in determining the BSER. As discussed above, the D.C. Circuit has emphasized this factor in describing the purpose of CAA section 111 as to achieve “as much [emission reduction] as practicable.” 516 b. Lack of incentive for technological innovation . As discussed above, the EPA is justifying its identification of the BS ER based on its weighing of the factors explicitly identified in CAA section 111(a)(1), including the amount of the emission reduction. Under the D.C. Circuit 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 above) . Consideration of this

516 Sierra Club , 657 F.2d at 327 & n. 83.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **429** of **763** factor confirms the EPA’s decision not to identify highly efficient generation technology (without CCS) as the BSER. At present, CCS technologies are the most promising options to achieve significant reductions in CO 2 emissions from newly constructed fossil fuel - fired steam generating units. CCS technology is also now a viable retrofit option for some modified, reconstructed and existing sources

– depending upon the configuration, location and age of those sources. As CCS technologies are deployed and used more there is an expectation that, based on previous experience with advanced technologies, the performance will improve and the implementation costs will decline. The improved performance and lower costs will provide additional incentive for further implementati on in the future. The Intergovernmental Panel on Climate Change (IPCC) recently released its Fifth Assessment report 517 , which recognizes that widespread deployment of CCS is crucial to reach the long term climate goals. The authors of the report used models to predict the likelihood of stabilizing the atmospheric concentration of CO 2 at 450 ppm by 2050 with or without carbon capture and storage (CCS). They found that several of the models were not able to reach this goal without CCS, which underlines the importance of deploying and further developing CCS on a
517 IPCC, Working Group III , Climate Change 2014: Mitigation of Climate Change, http://mitigation2014.org/report/publication/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **430** of **763** large scale. American Electric Power (AEP), in an evaluation of lessons learned from the Phase 1 of its Mountaineer CCS project, wrote: “AEP still believes the advancement of CCS is critical for the sust ainability of coal
- fired generation.” 518 Some commenters felt that the proposed standard of performance for new steam generating units, based on implementation of partial CCS at an emission rate of 1,100 lb/MWh - g , would not serve to promote the increased deployment and implementation of CCS. The commenters argued that such a standard could instead have the unintended result of discouraging the further development of advanced coal generating technologies such as ultra
- supercritical boilers and improved IGCC designs. Commenters further argued that such a standard will stifle further development of CCS technologies. Commenters felt that the standard would effectively deter the construction of new coal - fired generation

– and, if there is no new coal
- fired generation, then there will be no implementation of CCS technology and, therefore, no need for continued research and
518 CCS LESSONS LEARNED REPORT American Electric Power Mountaineer CCS II Project Phase 1, Prepared for The 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
-mountaineer
ii
-project
- front - end- engineering
- and- design
- feed- report .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **431** of **763** development of CCS technologies. They argued , in fact , that the best way to promot e the development of CCS was to set 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 would serve to promote development and deployment of that advanced control technology. On the contrary, the history of regulatory 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 requirement stifles technology development. There is a dramatic instance of this paradigm presented in the present record. In 2011, AEP deferred construction of a large - scale CCS retrofit demonstration project on one of its coal - fired power plants because the state’s utility regulators would not app rove cost recovery for CCS investments without a regulatory requirement to reduce CO 2 emissions. AEP’s chairman was explicit on this point, stating in a July 17, 2011 press release announcing the deferral:

We are placing the project on hold until economic and 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 owners of coal
- fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost
- effective***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **432** of **763** generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements t o reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share. 519 Some commenters also argued that the incremental cost associated with including CCS at the proposed level would prevent new coal - fired units from being built. Instead, they advocated for a standard based on most efficient technology (supercritical) coupled with government subsidies to 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 section V.H, the EPA has carefully evaluated those costs and finds them to be reasonable . Further, the record and current economic conditions (fuel costs, renewables, demand growth, etc.) show that non economic factors such as a desire for fuel diversity 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 reasonably modulated for this final standard) would make the difference between constructing and not constructing new coal capacity to be persuasive . Rather , a cost - reasonable standard reflecting use
519 http://www.aep.com/newsroom/newsreleases/?id=1704***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **433** of **763** of the new technology is what will drive new technology deployment. The EPA expects that it is unlikely that a new IGCC unit would install partial CCS to meet the final standard unless the facility is built to take advantage of EOR opportunities or to operate as a poly- generation facility (i.e., to co
-produce power along with chemicals or other products). For new IGCC units, the final standard of performance can be met by co - firing a small amount of natural gas. Some commenters argued that IGCC is an advanced technology that, like CCS, should be promoted. The EPA agrees. IGCC is a low
- emitting, versatile technology that can be used for purposes beyond just power production (as mentioned just above). Commenters further argued that a requirement to include partial CCS (at a level to meet the proposed standard of performance) would serve to deter

– rather than promote

– more installation of IGCC technology. We disagree with a similar argument that commenters make with respect to partial CCS for post - combustion facilities, but our final standard moots that argument for IGCC facil ities because the final emission limitation of 1,400 lb CO 2 /MWh - g will not itself deter installation of IGCC technology , by the terms of the commenters’ own argument . 2. “Full” Carbon Capture and S torage (i.e., 90 Percent Capture )***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **434** of **763** We also reconsidered whether the emission limitation for new coal - fired EGUs should be based on the performance of full implementation of CCS technology. For a newly constructed utility boiler, this would mean that a post
- combustion captu re system would be used to treat the entire flue gas stream 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 approximately 90 percent reduction in CO 2 emissions. In the proposal for newly constructed sources, we found that “full CCS” would certainly result in significant CO 2 reductions from any new source implementing the technology. However, we also found that the costs associated with implementation, on either a new utility boiler system or a new IGCC unit, are predicted to substantially exceed the 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 between cost of full capture and new nuclear technology is estimated to be even greater than at proposal. The EPA thus is not selecting full capture CCS as BSER. Q. Summary***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **435** of **763** The EPA finds that the best system of emission reduction adequately demonstrated is a highly efficient supercritical pulve rized coal boiler using post
- combustion partial 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 1,400 lb CO 2 /MWh
g, an emis sion limitation that is achievable over the 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 results in significant reduction in CO 2 emissions over a conventional SCPC unit without partial CCS, and the quantified health and climate benefits would exceed the cost of pollution control in all instances except, potentially, where the highest discount rate is assumed . This standard of performance is technically feasible, given that the BSER technology is already operating reliably in full
- scale commercial application . The technology adds cost to a new facility which the EPA has evaluated and finds to be reasonable because the costs are in the same range as those for new nuclear generating capacity

– a competing non -NGCC, dispatchable technology that utilities and project developers are also considering for baseload
application. The EPA has also considered capital cost increases associated with use of post
- combustion partial CCS at the level***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **436** of **763** needed to meet the final standard and found them to be reasonable , and within the range of capital cost increases for this industry in prior NSPS which have been adjudicated as reasonable. The EPA’s consideration of costs is also informed by its judgment that new coal
- fi red capacity would be constructed not as the most economic option , but for such purposes as preserving fuel diversity in an energy portfolio, and so would not be cost competitive with natural gas
- fired capacity, so that some additional cost premium may therefore be reasonable. The EPA has carefully evaluated the nonair 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 programs which assure prevention of environmental release during transport and storage. In addition, water use associated with use of partial CCS at the level to meet the final standard is acceptable, and use of the technology does not impose significant burdens on energy requirements at either the plant or national level. The 1,400 lb CO 2 /MWh - g standard reflecting performance of the BSER may be achieved without geographic constraint, both because 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 coal
- fired***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **437** of **763** plant is sited in an area without such access, that area has not already limited construction of new coal - fired capacity in some way , and the area cannot be serviced by coal
-by-wire . Accordingly , the EPA finds that the promulgated standard of performance for new fossil fuel
- fired steam electric generating units satisfies the requirements of CAA section 111(a). **VI. Rationale for Final Sta ndards for Modified**  **Fossil Fuel -**  **fired Electric Utility Steam Generating Units**  The EPA has determined that, as proposed, the BSER for steam generating units that trigger the modification provisions is each affected unit’s own best potential performance as determined by that unit’s historical performance. The final standards of performance are similar to those proposed in the June 2014 proposal. Differences between the proposed standards and the final standards issued in thi s action reflect responses to comments received on the proposal. Those changes are described below. As noted previously, the EPA is issuing final emission standards only for affected modified steam generating units that conduct modifications resulting in a hourly increase in CO 2 emissions (mass per hour) of more than 10 percent ("large" modifications) . The EPA i s continuing to review the appropriate standards for modified sources that conduct modifications resulting in a hourly increase in CO 2 emissions (mass per hour)***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **438** of **763** of less than or equal to 10 percent ("small" modifications) , is not issuing final standards for those sources in this action, and is withdrawing the proposed standards for those sources. See section XV below. A. Rationale for Final Applicability Criteria for Modified Steam Generating Units Final applicability criteria for modified steam generating EGUs include those discussed earlier in section III.A.1 (General Applicability) and section III.A.3 (Applicability Specific to Modified Sources). CAA section 111(a)(4) defines a “modification” as “any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” Certain types of physical or operational changes are exempt from consideration as a modification. Those are described in 40 CFR 60.2, 60.14(e). To be clear, our action in this final rule , and the discussion below, does not change anything concerning what constitutes or does not constitute a modification under the CAA or the EPA’s regulations. A modified steam generating unit is a source that fits the definition and applicability criteria of a fossil fuel
- fired steam generating unit and that commences a qualifying***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **439** of **763** modification on or after June 18, 2014 (the publication date of the proposed modification standards ) . 79 FR 34960 . For the reasons discussed below, the EPA in this final action is finalizing requirements only for steam generating units that conduct modifications resulting in an increase in hourly CO 2 emissions (mass per hour) of more than 10 percent as compared to the source’s highest hourly emission during the previous five years . With respect to modifications with smaller increases in CO 2 emissions (specifically, steam generating units that conduct modifications resulting in an increase in hourly CO 2 emissions (mass per hour) of 10 percent or less compared to the source’s highest hourly emission during the previous 5 years ) , the EPA is not finalizing any standard or other requirements,
and is withdrawing the June 2014 proposal with respect to these
sources (see section XV below) . The effect of EPA’s deferral on setting standards for sources undertaking modifications resulting in smaller increases in CO 2 emissions and the withdrawal of the June 2014 proposal with respect to such sources is that such sources will 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 definition of “new source” in section 111(a)(2), an existing source only becomes a new source if it modifies after the publication of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **440** of **763** proposed or final regulations that will be applicable to it. Thus, if an existing source modifi es at a time that there is no promulgated final standard or pending proposed standard 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 EPA is not finalizing standards for sources undertaking modifications resulting in smaller increases in CO 2 emissions and is withdrawing the proposal with respect to such sources, these sources do not fall within the definition of “new source” in section 111(a)(2) and continue to be an “existing source” as defined in section 111(a)(6). See section XV below. As we discussed i n 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 therefore predicted that very few of these units would trigger the modification provisions and be subject to the proposed standards. Given the limited information that we have about past modifications, the agency has concluded that it lacks sufficient information to establish standards of performance for all types of modifications at steam generating units at this time. Instead , the EPA has determined that it is appropriate to establish standards of performance at this time for larger
520 NSPS modifications resulting in increases in hourly emissions of criteria pollutants.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **441** of **763** modifications, su ch as major facility upgrades involving , for example, the refurbishing or replacement of steam turbines 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 publicly available information, that it has adequate information regarding the types of modifications that could result in large increases in hourly CO 2 emissions, as well as on the types of
meas ures available to control emissions from sources that undergo such modifications, and on the costs and effectiveness of such control measures, upon which to establish standards of performance for modifications with large emissions increases at this time. I n establishing standards of performance at this time for modifications with large emissions increases, but not for those with small increases, the EPA is exercising its policy discretion to promulgate regulatory requirements in a sequential fashion for cla sses of modifications within a source category, accounting for the information available to the agency, while also focusing initially on those modifications with the greatest potential environmental impact. This approach is consistent with the case law that authorizes agencies to establish a regulatory***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **442** of **763** framework in an incremental fashion, that is, a step at a time. 521 , 522 To be clear, the EPA is not reaching a final decision as to whether it will regulate modific ations with smaller increases, or even that such modifications should be subject to different requirements than we are finalizing in this rule for the modifications with larger increases. We have made no decisions and this matter is not concluded. We plan to continue to gather information , consider the options for modifications with smaller increases , and , in the future, develop a proposal for these modifications or otherwise take appropriate steps. As a means of determining the proper threshold between 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 fell regulatory swoop;’’ and instead they may permissibly implement such regulatory programs over time, ‘‘refining their preferred approach as circums tances change and as they develop a more nuanced understanding of how best to proceed.’’ See Grand Canyon Air Tour Coalition v. F.A.A., 154 F.3d 455 (DC Cir. 1998), City of Las Vegas v. Lujan, 891 F.2d 927, 935 (DC Cir. 1989), National Association of Broadcasters v. FCC, 740 F.2d 1190, 1209

– 14 (DC Cir. 1984). 522 As the D.C. Circuit stated in Hazardous Waste Treatment Council v. U.S. E.P.A ., 861 F.2d 277, 287 (D.C. Cir. 1988)."[A]n agency's failure to regulate more comprehensively is not ordinarily a basis fo r concluding that the regulations already promulgated are invalid. 'The Agency might properly take one step at a time.' United States Brewers Assoc. v. EPA, 600 F.2d 974,982 (D.C. Cir. 1979). Unless the agency's first step takes it down a path that fore closes more comprehensive regulation, the first step is not assailable merely because the agency failed to take a second. The steps may be too plodding, but that raises an entirely different issue . . . ."***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **443** of **763** larger and smaller increases in CO 2 emissions, the EPA examined changes in CO 2 emissions that may result from large, capital
intensive projects, such as major facility upgrades involving the refurbishing or replacement of steam turbines and other equipment upgrades that would significantly increase a unit's capacity to burn more fossil fuel, thereby resulting in large emissions increases. Major upgrades such as these could increase a steam generating unit 's hourly CO 2 emissions by well over 10 percent . 523 An example of such major upgrade would be work performed 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 improvements that raised maximum unit capacity by nearly 10 percent (from 580 MW to 630 MW). 524 Those changes included boiler improvements necessitated by its switch from bituminous to s ubbituminous coal 525 , installation o f low-NOX burners, an overfire air system, and advanced computer controls. One of the performance gains
523 See e.g., Power Engineering, Steam Turbine Upgrades Boost Plant Reliability, Efficiency, available at www.power
eng.com/articles/print/volume
- 116/issue
- 11/features/steam
turbine
- upgrades -boost -plant - reliability
- efficiency.html. 524 “Steam turbine upgrading: Low
-hanging fruit”, Power (04/15/2006), www.powermag.com/steam
- turbine
- upgrading
- lowhanging
- fruit. 525 Note that a change in coal
- type or change in the use of other raw material does not necessarily constitute an “operational change”. See 40 CFR 60.14(e)(4).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **444** of **763** 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’ existing outer casing . Another example is the refurbishment of the 2,100 MW 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. 526 For each of the plant’s six steam generating units, the company conducted a complete retrofit of the high pressure and intermediate pressure steam turbines, a capacity upgrade of the low pressure st eam turbine , and the replacement and upgrade of associated turbine side pumps and auxiliaries. In addition, major upgrades to the boiler plant were conducted, including supply of new pressure part components, new burners, and modification to other equipment such as the coal mills and classifiers, fans , and heaters. Other examples are provided in a technical memo available in the rulemaking docket. 527 The EPA does not intend to imply that these specific projects would have result ed in an increase in hourly CO 2

526 www.alstom.com/press
- centre/2006/10/alstom
- signs
-power -plant upgrade - and- retrofit
- contract -with
- eskom- in
- south - africa/ 527 See “ U.S. DOE Information Relevant to Technical Basis for “Large Modification” Threshold” available in the rulemaking docket EPA- HQ - OAR- 2013
- 0495.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **445** of **763** emissions of greater than 10 percent. C apacity increases are often the result of efficient improvements or are accompanied by other facility improvements that can offset emissions increases due to increased fuel input capacity. However, the se examples are intended to show the types of large, more capital intensive projects that can potentially result in increases in hourly emissions of CO 2 of at least 10 percent . The EPA believes that it is reasonable to set the threshold between “ large ” modifications and “ small ” modifications at 10 percent, a level commensurate with the magnitude of the emissions increases that could result from the types of projects described above , and we are issuing a final standard of performance for those sources that conduct modifications resulting in hourly CO 2 emission increases that exceed that threshold. We are not issuing standards of performance for those 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 standards for those sources that conduct modifications resulting in a hourly increase in CO 2 emissions (mass per hour) of less than or equal to ten percent and is not issuing final standards for those sources at this time. S ee section XV below. Utilities, states and others should be aware that the differentiation between modifications with larger and smaller increases in CO 2***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **446** of **763** emissions only applies to sources covered under 40 CFR part 60 , subpart TTTT , i.e . , i t 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 source categories. Utilities, states and others should also be aware that the distinction between large and small modifications only applies to NSPS modifications. Sources undertaking modifications may still be subject to requirements of New Source Review under CAA part C or D (which have different standards for modifications than the NSPS and require a case
-by- case analysis) or other CAA requirements . The EPA notes that some commenters expressed concern that a number of existing fossil steam generating units, in order to fulfill requirements of an approved CAA section 111(d) plan, may pursue actions that involve physical or operational changes that result in some increase in their CO 2 emissions on an hourly basis, and thus constitute modifications. Some commenters suggested that the EPA should exempt projects undertaken specifically for the purpose of complying with CAA section 111(d). The EPA does not have sufficient information at this time to predict the full array of actions that existing steam generating units may undertake in response to applicable requirements under an approved CAA section 111(d) plan, or***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **447** of **763** which, if any, of these actions may result in increases in CO 2 hourly emissions. Nevertheless, the EPA expects that, to the extent actions undertaken by existing steam generating units in response to 111(d) requirements trigger modifications, the magnitude of the increases in hourly CO 2 emissions associated with such modifications would generally be small er and would therefore generally not subject such modifications to the standards of performance that the EPA is finalizing today for modified steam generating units with large r increases in hourly CO 2 emissions. We note that modified steam generating units that are not subject to the standard of performance finalized in this rule would be existing sources subject to section 111(d). 528 B. Identification of the Best System of Emission Reduction The EPA has determined that, as was proposed, the BSER for steam generating units that trigger the modification provisions
528 Any source that undergoes a modification resulting in CO 2 increases of less than 10 percent will continue to be an “existing source” 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 sour ce. Under the definition of “new source” in section 111(a)(2), a modified source is a new source only if the modification occurs 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 the modifications with small CO 2 increases, and are withdrawing the proposal with respect to such sources, there are neither final regulations nor pending proposed regulations which will be applicable to such modifications.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **448** of **763** is the affected EGU’s own best potential performance as determined by that source’s historical performance. The EPA proposed that the BSER for modified steam generating EGUs is each unit’s own best potential performance based on a combination of best operating practices and equipment upgrades. Specifically, the EPA co
-proposed two alternative standards for modified utility steam generating units. In the first co
-proposed alternative, modified steam generating EGUs would be subje ct to a single emission standard determined by the affected EGU’s best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction. The EPA proposed that the standard could be met through a combination of best operating practices and equipment upgrades. To account for facilities that have already implemented best practices and equipment upgrades, the proposal also specified that modified facilities would not have to meet an emi ssion standard more stringent than the corresponding standard for reconstructed EGUs.The EPA also co -proposed that the specific standard for modified sources would be dependent on the timing of 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

—***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **449** of **7 63**  that is, the modified source would be required to meet a unit
specific emission limit determined by the affected EGU’s best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction (based on equipment upgrades). We also proposed that sources that modify after becoming subject to a CAA section 111(d ) plan would be required to meet a unit
specific 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 effici ency improvement opportunities. The final standards in this action do not depend upon when the modification commences (as long as it commences after June 8, 2014). The EPA received comments on the June 2014 propos al that called into question the need to differentiate the standard based on when the modification was undertaken. Further, commenters noted that the proposed requirements for sources modifying after becoming subject to a CAA section 111(d) plan, which were based on energy efficiency improvement opportunities were vague and that standard setting under CAA section 111(b) is a federal duty and would require notice
- and- comment rulemaking. The EPA considered those comments and has determined that we agree that there is no need for subcategories based on the timing of the modification.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **450** of **763** C. BSER Criteria 1. Technical Feasibility The EPA based technical feasibility of the unit
- specific efficiency improvement on analyses done to support heat rate improvement for the proposed CAA section 111(d) emission guidelines (Clean Power Plan). That work was summarized in Chapter 2 of the TSD, “GHG Abatement Measures ”. 529 In response to comments on the proposed Clean Power Plan, the approach was adjusted, as described in the final CAA section 111(d) emission guidelines. As with proposed actions, the EPA is basing technical feasibility for final standards for modified source efficiency improvements on the analyses for heat rate improvements for the CAA 111(d) final rule. 2. Cost Any efficiency improvement made by EGUs for the purpose 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 estimate that, on average, the savings in fuel cost associated with a 4 percent heat rate improvement would be sufficient to cover much of the
529 Technical Support Document “GHG Abatement Measures” available in the rulemaking docket EPA
- HQ - OAR- 2013
- 0495.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **451** of **763** associated costs, and thus that the net costs of heat rate improvements associated with reducing CO 2 emissions from affecte d EGUs are relatively low. We recognize that our cost analysis just described will represent the costs for some EGUs better than others because of differences in EGUs’ individual circumstances. We further recognize that reduced generation from coal
- fired E GUs will tend to reduce the fuel savings associated with heat rate improvements, thereby raising the effective cost of achieving the CO 2 emission reductions from the heat rate improvements. Nevertheless, we still expect that the majority of the investment required to capture the technical potential for CO 2 emission reductions from heat rate improvements would be offset by fuel savings, and that the net costs of implementing 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 intensive projects that may trigger the “larger modifications” threshold (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 in CO 2 emissions from the affected modified units as those units will***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **452** of **763** be required to meet an emission standard that is consistent with more efficient operation. In light of the limited opportunities for emission reductions from retrofits, these reductions are adequate. 4. Promotion of technology and other systems of emission reduction As note d previously, the case law makes clear that the EPA is to consider the effect of its selection of the BSER on technological innovation or development, but that the EPA also has the authority to weigh this factor, along with the various other factors. With the selection of emissions controls, modified sources face inherent constraints that newly constructed greenfield and even reconstructed sources do not; as a result, modified sources present different, and in some ways more limited, opportunities for technological innovation or development. In this case, the standards promote technological development by promoting further development and market penetration of equipment upgrades and process changes that improve plant efficiency. **VII. Rationale for Final Stan dards for Reconstructed**  **Fossil Fuel**  **- fired**  **Electric Utility Steam Generating Units** A. Rationale for Final Applicability Criteria for Reconstructed Sources***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **453** of **763** The applicability rationale for reconstructed utility steam generating units is the same as for newly constructed utility steam generating units. We are finalizing the same general criteria and not amending the reconstruction provisions included in the general provisions. B. Identification of the Best System of Emission Reduction In the proposal, the EPA evaluated seven different control technology configurations to determine the BSER for reconstructed fossil fuel
- fired boiler and IGCC EGUs: (1) The use of partial CCS, (2) conversion to (or co
- firing with) natural gas, (3) the use of CHP, (4) hybrid power plants , (5) reductions in generation associated with dispatch changes, renewable generation, and demand side energy efficiency,(6) efficiency improvements achieved through the use of the most efficient generation technology, and (7) efficiency improvements achieved through a combination of best operating practices and equipment upgrades. Although the EPA concluded that the first 4 technologies met most of the evaluation criteria, namely they are adequately demonstrated, have reasonab le costs and provide GHG emissions reductions, they were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. We rejected best operating practices and equipment upgrades because we concluded the GHG reductions are not sufficient to qualify as***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **454** of **763** BSER. The majority of commenters agree with EPA's decision that these technologies are not BSER. In contrast, as described in more detail later in this section a few commenters did support partial CCS as BSER. The fifth option, reductions in generation associated with dispatch changes, renewable generation, and demand side energy efficiency, is comparable to application of measures identified in building blocks two, three and four in the emissions 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 building blocks two, three and four in the BSER determination. Most commenters stated that building blocks two, three and four should not be considered for reconstructed sources . The proposed BSER was based on the performance of the most efficient generation technology available, which we concluded was the use of the best available subcrit ical 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, to have reasonable costs, and some opportunity for technol ogical innovation. The proposed emission standard for these sources was 1,900 lb CO 2 /MWh - n for units with a heat input rating of greater than 2,000 MMBtu/h and 2,100 lb CO 2 /MWh - n for units with a heat***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **455** of **763** input rating of 2,000 MMBtu/h or less. The difference in the proposed standards for larger and smaller units was based on greater availability of higher pressure/temperature steam turbines (e.g. supercritical steam turbines) for larger units. As explained in S ection III of this preamble , we are finalizing the standard on a gross output basis for utility steam generating units. The equivalent gross
- output -based standards are 1,800 lb CO 2 /MWh and 2,000 lb CO 2 /MWh respectively. We solici ted comment on multiple aspects of the proposed standards. First, we solicited comment on a range of 1,600 to 2,000 lb CO 2 /MWh - g for large units and 1,800 to 2,200 lb CO 2 /MWh g for small units. We also solicited comment on whether the standards for utility boilers and IGCC units should be subcategorized by primary fuel type. In addition, we solicited comment on if there are sufficient alternate compliance 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. Many commenters support ed the upper limits of the suggested ranges, saying the standard will be consistently met. Some commenters raise d concerns about the achievability of these limits for the many boiler and fuel types. A few commenters suggest ed that there should be separate subcategories for coal
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– Do Not Cite, Quote or Release During Review *** Page **456** of **763** fired utility boilers and IGCC units, since IGCC units have demonstrated limits closer to 1,500 lb CO 2 /MWh - n and the units' designs are so fundamentally different. Some commenters sa id that CFB (due to lower maximum steam temperatures), IGCC, and traditional boilers each need their own subcategory. Some commenters suggest ed that due to high moisture content 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 thought the BSER determination for reconstructed subpart Da units was inconsistent with the BSER determination for newly constructed units. These commenters stated that the EPA did not provide sufficient justification for eliminating partial carbon capture and sequestration (CCS). These commenters also stated that the reason the EPA gave for dismissing CCS in the proposal was a lack of "sufficient information about costs." These commenters hold that the cost rationale does not apply for reconstructed coal - fired power plants. The fact that reconstructed units may face greater costs to comply with a CAA section 111(b) standard than new sources does not relieve them of their compliance obligation. Based on a review of the comments , we have concluded that both the proposed BSER and emission standards are appropriate, and we are finalizing the standards as proposed. Nothing in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **457** of **763** comments changed our view that the BSER for reconstructed steam generating units should be based on the performance of a well operated and maintained EGU using the most efficient 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 for small units. As described at proposal, we have concluded that these standards are achievable by all the primary coal types. The final standards for reconstructed util ity boilers and 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 i dentified BSER, a reconstructed EGU would not necessarily have to rebuild the boiler to use steam temperatures and pressures that are higher than the original design. As commenters noted, a reconstructed unit is not required to meet the standards if doing so is deemed to be "technologically and economically" infeasible. 40 CFR 60.15(b). This provision inherently requires
case -by- case reconstruction determinations in the light of considerations of economic and technological feasibility. However, this case
-by- case determination would consider the identified BSER (the use of the best available steam conditions), as well as
-- at a minimum
-- the first four***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **458** of **763** technologies the EPA considered, but rejected, as BSER 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 result in sufficient GHG reductions to comply with the applicable reconstructed standards. Finally, in some cases, equipment upgrades and best operating practices would result in sufficient reductions to achieve the reconstructed standards. **VIII. Summary of Final Standards for Newly Constructed and Reconstructed Stationary Combustion Turbines**  This section summarizes the final applicability requirements , BSER determinations , and emission standards for newly constructed and reconstructed stationary combustion turbines. In addition, it also summarizes significant differences between the proposed and final provisions. A. Applicability Requirements We are finalizing BSER determinations and emission standards for newly constructed and reconstructed stationary combustion turbines that (1) have a base load rating for fossil fuels greater than 260 GJ/h ( 250 MMBtu/h ) and (2) serve a generator capable of selling more than 25 MW
- net of electricity to the grid. We also are finalizing applicability requirements that will exempt from the final standards (1) all stationary combustion turbines that are dedicated non
- fossil fuel - fired***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **459** of **763** units (i.e., combustion turbines capable of combusting 50 percent or more non - fossil fuel ) and subject to a federally enforceable permit condition restricting annual fossil fuel use to 10 percent or less of a 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 multiplied by the unit’s potent ial output , or 219,000 MWh, whichever is greater ); (3) combustion turbines that are physically incapable of burning natural gas (i.e., not connected to a natural gas pipeline ); and (4) municipal waste combustors and commercial or industrial solid waste inc inerators (units subject to subparts Eb or CCCC of this part). For combustion turbines subject to an emission standard, we are finalizing three subcategories: base load natural gas - fired units, non -base load natural gas - fired units, and multi
- fuel fired units. We use the term base load natural gas - fired units to refer to stationary combustion turbines that (1) burn over 90 percent natural gas and (2) sell electricity in excess of their design efficiency (not to exceed 50 percent) multiplied by their potent ial electric output. To be in this subcategory, a stationary combustion turbine must exceed the “ natural gas - use criterion ” on a 12
- operation month rolling average and the***EO 12866_Review
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“percentage electric sales ” criteri on on both a 12
- operating month and 3
- year rolling average basis. We use the term non -base load natural gas - fired units to refer to s tationary combustion turbines that (1) burn over 90 percent natural gas and (2) have net - electric sales equal to or below their design efficiency (not to exceed 50 percent) multiplied by their potential electric output. These criteria are calculated on the same rolling average bases as for the base load subcategory. Finally,
we use the term multi
- fuel - fired units to refer to stationary combustion turbines that burn 10 percent or more non
- natural gas on a 12
- operating month roll ing average basis. We are not finalizing the proposed emission standards for modified sources and are withdrawing those standards . We explain our rationale for these final decisions in Section s IX and XV of this preamble. B. Best System of Emission Reduction We are finalizing BSER determinations for the three subcategories of stationary combustion turbines referred to above : base load natural gas - fired units, non -base load natural gas - fired units, and multi
- fuel - fired units . For newly constructed and reconstructed base load natural gas - fired stationary combustion turbines , the BSER is the use of efficient NGCC technology. For newly constructed and reconstructed non base load natural gas - fired stationary combustion turbines, the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **461** of **763** BSER is the use of clean fuels (i.e., natural gas with an allowance for a small amount of distillate oil ) . For multi
- fuel fired stationary combustion turbines , the BSER is also the use of clean fuels ( e . g ., natural gas, ethylene, propane, naphtha, jet fuel kerosene, distillate oil s 1 and 2, biodiesel, and landfill gas) . C. Final Emission Standards For all newly constructed and reconstructed base load natural gas - fired combustion turbines , we are finalizing 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 1,03 0 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 combustion 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 - fired combustion turbines , we are finalizing a standard of 120 to 160 lb CO 2 /MMBtu, calculated on a 12
- operating month rolling average basis. The emission standard for multi
- fuel - fired c ombustion turbines co
- firing natural gas with other fuels shall be determine d at the end of each operating month based on the percentage of co - fired natural gas . Table 15 summarizes the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **462** of **763** subcategories , BSER determinations , and emission standards for combustion turbines. **Table 15**  **: Combustion Turbine Subcategories and BSER**

D. Significant Differences between Proposed and Final Combustion Turbine Provisions As shown in Tables 16 and 17 below , the proposed rule 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 approach" that include d most combustion turbines irrespective of the actual amount of electricity sold to the grid or the actual amount of natural gas burned (i.e., non -base load units and multi
- fuel fired units , respectively ). The broad applicability approach changed the proposed " percent age electric sales " and "natural

530 The emission standard for c ombustion turbines co
- firing natural gas with other fuels shall be determine d based on the amount o f co - fired natural gas at the end of each operating month. **S ubcategory**  **BSER Emission**  **standard** Base load natural gas - fired combusiton turbine s Efficient NGCC 1,000 lb CO 2 /MWh g or 1,030 lb CO 2 /MWh - n Non -base load natural gas - fired combustion turbine s Clean fuels 120 lb CO 2 /MMBtu
Multi fuel
- fired combus t i on turbine s Clean fuels 120 t o 160 lb CO 2 /MMBtu 530***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **463** of **763** gas - use " criteria to distinguish among subcategory
- specific emissions standards. Specifically, in the broad applicability approach , we solicited comment on subjecting non -base load units and multi
- fuel - fired units to "no emissions standard , " while still including them in the general applicability. We also solicited comment on establishing a separate numerical standard for non -base load units . The final rule retains all of the proposed applicability criteria in some form , but most closely tracks the broad applicability approach by finalizing the percentage electric sales and natural gas
- use criteria as thresholds that distinguish among three subcategories of combustion turbines with separate emissions standards. The final rule also includes exceptions to the broad applicability approach that we solicited comment on , with some changes that are responsive to public comments. Categorical exceptions to the broad applicability criteria are the exclu sions for CHP units , non - fossil fuel unit s , and combustion turbines not able to combust natural gas . First , the proposed applicability criteria did not include CHP units that were const ructed for the purpose of or that actually sell one - third or less of their potential electric output or 219,000 MWh, whichever is greater, to the grid . The final rule eliminates the “constructed for the purpose of” and actual sales aspects of the proposal and replaces them with an exemption for CHP units that***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **464** of **763** take federally enforceable permit conditions restricting net
electric sales to a percent age of potential electric sales based on the unit’s design efficiency or 219,000 MWh, whichever is greater. Second, the proposed applicability criteria 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 the proposal with an exemption for non - fossil fuel units that take federally enforceable permit condition s limiting fossil
- fuel use to 10 percent or less of annual heat input capacity . Finally, the proposed applicability criteria did not include combustion turbines that burn 90 percent or less natural gas on 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 combustion turbines that are not connected to natural gas p ipelines . Finally, in response to public comments, we are not finalizing the subcategories for large and small combustion turbines that were contained in the proposal . Instead, all base load natural gas fired combustion turbines must meet an emission standard of 1,000 lb CO 2 /MWh
- g. **Table 16**  **: Proposed Applicability Criteria versus Final Applicability Criteria**  **Applicability Criteria**  **Proposed Applicability Final Applicability** ***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **465** of **763** Base load rating criterion Base load rating > 73 MW

(250 MMBtu/h) Base load rating > 260 GJ/h 531 (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 net s ales to the grid > one third of potential electric output Changed to subcategorization criterion per broad applicability approach Natural gas use 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 supply Fossil fuel
use criterion Actually burns > 10

percent fossil fuel Exemption based on permit condition limiting amount of fossil fuel burned to ≤ 10 percent of annual heat input capacity Combined Heat and Power (CHP) exemption NA Exemption based on permit condition limiting net
- electric sales to ≤ design efficiency multiplied by potential electric output, or 219,000 MWh - n, whichever is greater

531 73 MW is equivalent to 260 GJ/h. We changed units to avoid potential confusion of MW referring to electric output rather than heat input.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **466** of **763** 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 Subcategories 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 load natural gas fired 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 load natural gas fired 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 Multi
- fuel fired combustion turbine subcategory NA Actually burns ≤ 90 percent natural gas

**IX. Rationale for Final Standards for Newly Constructed and**  **Reconstructed Stationary Combustion Turbines*****EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **467** of **763** This section discusses the EPA’s rationale for the final applicability criteria, BSER determinations , and standards of performance for newly constructed and reconstructed stationary combustion turbines. In this section, we present a summa ry of what we propose d , a selection of the significant comments we received, and our rational e for the final determinations , including how the comments i nfluenced our decision
-making . A. Applicability This section describes the proposed applicability criteria , applicability issues we specifically solicited comment on, the relevant significant comments, and the final applicability criteria. We also provide our rationale for finalizing applicability criteria based strictly on design and permit restrictions rather than actual operating characteristics . Finally, we explain why the proposed percent age electric sales and natural gas - use applicability criteria are being 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 turbines . Specifically, to be subject to the proposed emission standards , we proposed that a unit must (1) be capable of combusting more than 73 MW ( 250 MMBtu/h ) heat input of fossil fuel; (2) be***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **468** of **763** constructed for the purpose of supplying and actually supply more than one - third of its potential electric output capacity to a utility power distribution system for sale (that is, to the grid) on a 3
- year rolling average ; (3) be constructed 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 rolling average; and (5) combust over 90 percent natural gas on a 3
- year rolling average. We proposed exempting municipal solid waste combustors and commercial and industrial solid waste incinerators. Under these proposed applicability criteria, two types of stationary combustion turbines that are current ly subject to criteria pollutant standards under subpart KKKK would not have been subject to CO 2 standards . The first type was stationary combustion turbines that are constructed for the purpose 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., multi
fuel - fired units ) . We proposed the e lectric sales criteri a in part because they already exist in other regulatory context s (e.g., the coal fired EGU criteria pollutant NSPS) and would promote consistency***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **469** of **763** between regulations. Our understanding at proposal was that the percentage electric sales criteri on would distinguish between
non -base load units ( e . g ., low capital cost, flexible, but relatively inefficient simple cycle units) and base load un its (i.e., higher capital cost, less flexible, but relatively efficient combined cycle units). While the proposed applicability criteria did not explicitly exempt simple cycle combustion turbines from the emission standards , we concluded that , as a practical 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 one third electric sales threshold . a . Solicitation of comment on applicability, generally . We solicited comment on a range of issues related to applicability. In conjunction with the proposed one - third (i.e., 33.3 percent) electric sales threshold , we solicited comment on
a threshold between 20 to 40 percent of potential electric output . We also solicited comment on a variable percentage electric sales criterion, which would allow more efficient, lower emitting turbines to run for longer periods of operation before becoming subject to the standards of performance . Under this “sliding scale” approach , the percentage electric sales***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **470** of **763** criterion would be based on the net design efficiency of the combustion turbine being installed . In this way, more 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 emission standard . This approach had the benefit of incentivizing the development and installation of more efficient simple cycle combustion turbines to serve peak load. We also solicited comment on whether the percentage electric sales criterion for stationary combustion turbines should be defined on a single calendar ye ar 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
- efficient stationary combustion turbines that would be exempt due to their lower output . We further solicited comment on whether to provide an explicit exemption for all simple cycle combustion turbines regardless of the amount of electricity sold . We additionally solicited comment on how to imp lement the proposed electric sales , fossil fuel - use , and natural gas - use criteria given that they were to be evaluated as 3
- year rolling averages during the first three years of operation , and we requested comment on appropriate monitoring, recordkeeping, and reporting requirements . We specifically solicited comment on whether these***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **471** of **763** proposed requirements raise d implementation issues because they
were based on source operation after construction has occurred. We also s olicited comment on excluding electricity sold during system emergencies from the calculation of percent age electric sales. The rationale for this exclusion was that simple cycle combustion turbines intended only for peaking applications might be required to operate above the proposed percent age electric sales threshold if a major power plant or transmission line became unexpectedly unavailable for an extended per iod of time. The EPA proposed that this flexibility would be appropriate if the unit were called upon to run after all other available generating assets were already running at full load. b. Solicitation of comment on b road applicability approach . In both the January 2014 proposal for newly constructed EGUs and the June 2014 proposal for modified and reconstructed EGUs, the EPA solicited comment on finalizing a broad applicability approach instead of the proposed approach . Under the proposed approach, a stationary combustion turbine could be an affected EGU one year, but not the next, depending on the unit’s actual electric sales and the composition of fuel burned. The broad applicability approach is consistent with historic al NSPS applicability approaches that are based on design criteria and include different emission standards for subcategories that
are distinguished by operating characteristics. Specifically, we***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **472** of **763** solicited comment on whether we should completely remove the electric sales and natural gas - use criteria from the general applicability framework . I nstead , the percentage electric sales and natural gas - use thresholds would serve as subcategorization criteria for distinguishing among classes of EGUs and subcategory- specific emission s standards . Under this broad applicability approach, the “constructed for the purpose of” component of the percentage electric sales criteri on would be completely eliminated so that applicability for combustion 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 contrast to the proposed applic ability criteria , under the broad applicability approach , non -base load (e.g ., simple cycle) and multi
- fuel - fired (e. g ., oil
- fired) combustion turbines would remain subject to the rule regardless of the ir electric sales or fuel use. We solicited comment on all aspects of this "broad applicability approach," including the extent to which it would achieve our policy objective of assuring that owners and operators install NGCC combustion turbine s if they plan to sell more than the specified electric sales threshold to the grid. 2. Comments on Applicability***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **473** of **763** This section summarizes the comments we received specific 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 approach. 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 with the threshold used in states participating in the Regional Greenhouse Gas Initiative ( RGGI ) and under Title IV programs. Other commenters opposed the proposed applicability thresholds and stated that all new, modified, and reconstructed 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 energy markets as they would not be required to internalize the costs of compliance. b . Total e lectric sales criteri on . Commenters noted that the 219,000 MWh total electric sales threshold put larger combustion turbines at a competitive disadvantage by distorting the market and could have the perverse impact of increasing CO 2 emissions. These commenters noted that the 219,000 MWh total electric sales threshold would***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **474** of **763** allow combustion turbines smaller than approximately 80 MW to sell more than one - third of their potential electric output, but larger, more efficient combustion turbines would still be restricted to selling one
- third of their potential electric output to avoid triggering the NSPS. They argued that this would result in a regulatory incentive fo r generators to install multiple, less
- efficient combustion turbines instead of fewer,
more - efficient combustion turbines and could have the unintended consequence of increasing CO 2 emissions.
c. Percentage electric sales criteri on . Commenters from the power sector generally supported a complete exemption for simple cycle turbines. These commenters stated that simple cycle turbines are uniquely capable of achieving the ramp rates (the rate at which a power plant can increase or decrease output ) necessary to respond to emergency conditions and hourly variations in output from intermittent renewables. Commenters noted that simple cycle combustion turbines serve a different purpose than NGCC power blocks . In addition, commenters noted that electricity generation dispatch is based on the incremental cost to generate electricity and that because NGCC units have a lower incremental generation cost than simple cycle units, economics will drive the use of NGCC technologie s over simple cycle units. However, commenters also stated that historic simple cycle operating data may not be***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **475** of **763** representative of future system requirements as coal units retire, generation from intermittent renewable generation increases, and numerous market and regulatory drivers impact plant operations. In the absence of a complete exemption, these commenters supported a percentage electric sales threshold between 40 to 60 percent of a unit’s potential electric output . Some commenters said that becaus e the proposed percentage electric sale s criterion applied over a three
- year period , it would adversely affect grid reliability because operators conservatively would hedge short - term operating decisions to
ensure that they have sufficient capacity to respond to unexpected scenarios during future compliance periods when the demand for electricity is higher. These commenters were concerned that such compliance decisions would drive up the cost of electricity as the most efficient new units are taken out of
s ervice to avoid triggering the NSPS and older, less efficient units with no capacity factor limitations are ramped up instead. Some commenters supported the sliding
- scale approach (i.e. , a percentage electric sales threshold based on the design efficiency of the combustion turbine) and stated that incentives for manufacturers to develop ( and end users to purchase ) higher efficienc y combustion turbines could help mitigat e concerns about a monolithic national constraint on simple cycle capacity factors.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **476** of **763** In contrast, others commented that fast - start NGCC units intended for peaking and intermediate load applications can achieve comparable ramp rates to simple cycle combustion turbines , but with lower CO 2 emission rates . These commenters said that simple cycle turbines should be restricted to their historical role as true peaking units and that the proposed one third electric sales threshold provide d sufficient flexibility. Some commenters suggested that the one - third electric sales threshold could be reduced to 20 percent or lower without adverse impact s on grid reliability. Commenters noted that a complete exclusion for simple cycle turbines would create a regulatory incentive for generators to install and operate less efficient unaffected units instead of more efficient affected units , thereby increasing CO 2 emissions . According to these commenters , any applicability distinctions should be based on utilization and function rather than purpose or technology. Commenters in general supported the use of 3
- year rolling average s instead of a single
- year average for the percentage and total electric sales criteri a because , in their view, the 3
- year rolling average s would provide a better overall picture of normal operations . Some commenters stated that a rolling 12
- month or calendar - year average could be severely skewed in a given year because of unforeseen or unpredicted events. They***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **477** of **763** said that using a 3
- year averaging methodology would provide system operators with needed flexibility to dispatch simple cycle units at higher than normal capacity factors . In contrast,
some c ommenters stated that , because capacity is forward
- looking (e.g., payments for capacity are often made several years in advance) , the 3
- year averaging period provides limited benefit because owner/operators need to reserve the ability to respond to unforeseen events . Commenters noted that potential compliance issues could result from the inconsistent time frame between the 3
- calendar year applicability period and the 12
- operating
-month compliance period . For example, a facility could sell more than one - third of its potential electric output over a 3
- year period , but sell less than one - third of its potential electric output during any given 12
- operat i ng month compliance period with in 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 and have multiple starts and stops. These operating conditions have the potential to increase CO 2 emission s , regardless of the deign efficiency of the turbine . Therefore , a unit could have am emission rate in excess of the proposed standard. Regarding the relationship between the percentage electric sales criteri on and system emergencies, multiple commenters***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **478** of **763** supported exclusion of electricity generated as a result of a system emergency from counting towards net sales. These commenters stated that the exclusion was appropriate because the benefits of operating these units to generate electrical power during emergency conditions would outweigh any adverse impacts from short - term increases in CO 2 emissions. One commenter stated that , in addition to declared grid emergencies, other circumstances might warrant emergency exemption under the rule, including extreme market conditions, limitat ions 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 appl y continuously, even during system emergencies. The se commenters stated that the EPA does not have the authority under the CAA to suspend the applicability of a standard during periods 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 that the government will not sue the source for taking certain actions during an emergency. Commenters said that this enforcement discretion approach has provided prompt, flexible relief that is tailored to the needs of the particular emergency and the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **479** of **763** communities being served and is only utilized where the relief will address the particular emergency at hand. Commenters added that this enforcement discretion approach is consistent with the CAA’s mandate that emission limits apply continuously and provide safeguards against abuse. One commenter stated that emergencies happen rarely and typically last for short periods, that the proposed percentage electric sales threshold would allow a source to operate at its full rated capacity for up to 2,920 hours per year without triggering applicability , and that the potential occurrence of grid emergencies would represent a ti ny fraction of this time. Another commenter stated that no emergency short of large scale destruction of power generating capacity by terrorism, war, accident, or natural disaster could justify operating 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 whether the proposed applicability requirements that retrospectively look back at actual events ( i.e., the electric sales and fuel use criteria) would create implementation issues, several permitting authorities opposed the provisions because units could be subject to coverage one year but not the next, result ing in compliance issues and difficulties in determining***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **480** of **763** proper pre - construction and operating permit conditions. These permitting authorities suggested that in order for a source to avoid applicability, the source should be subject to a federally enforceable permit condition with associated monitoring, recordkeeping, and reporting conditions for assessing applicability on an ongoing basis. Other commenters stated that an applicability test that concludes after construction and operation have commenced is inconsistent with the general purpose of an applicability test

—to provide clear and predict able standards of performance for new sources that would apply when they begin operations. Some c ommenters opposed the proposed retrospective applicability criteria related to actual output supplied during a preceding compliance period because EGUs must know what performance standards will apply to them during the licensing process , and such criteria do not allow the permitting authority and the public to know in advance whether an emission standard applies to a proposed new unit. Other c ommenter s said that EGUs undergoing permitting should be allowed to request limits in their operating permit conditions in order to remain below the applicability thresholds , as this methodology is consistent with the pre - construction permitting requirements in many federa lly approved SIPs and the current approach under the Title V permitting program.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **481** of **763** Many commenters stated a preference for the "proposed applicability approach" over the "broad applicability approach." These commenters did not think it was necessary to requ ire non base load or multi
- fuel - fired combustion turbines to be subject to emission standards . They stated that there is no justification for imposing burdensome monitoring, reporting, and recordkeeping requirements that would have no environmental benefit (i.e., would not reduce CO 2 emissions) because these units would be subject to "no emissions s tandards **."** Other commenters supported the broad applicability approach and stated that all new, modified, and reconstructed units that sell electricity to the grid, including small EGUs, oil
- fired combustion turbines, and simple cycle combustion turbines s hould be affected EGUs because they would otherwise have a competitive advantage in energy markets as they would not be required to internalize the costs of compliance. In contrast, to preserve the discretion of state planners under section 111(d), many other commenters supported the broad applicability approach and the inclusion of new simple cycle units within the scope of the section 111(b) emission standards so that similar, existing simple cycle units could be subject to the 111(d) standards . Numerou s other commenters stated that all units that sell electricity to the grid should be subject to a standard, including simple cycle units, because they view the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **482** of **763** 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 frameworks 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 practical implementation issues, we are revising how those criteria will be implemented. The final applicability criteria for combustion turbines are generally consi stent with the broad applicability approach on which we solicited comment. Section VIII of this preamble presents each proposed applicability criterion together with the form of the criterion in the final rule. The final general applicability framework inc ludes the proposed 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 multiple exemptions that are relevant to combustion turbines: combustion turbines that are not connected to natural gas pipelines ; CHP facilities with federally enforceable limits on total electric sales; and EGUs undertaking modifications with hourly emissions increases of 10 percent or less. The final appl icability framework reflects multiple variations from the proposal that are responsive to public***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **483** of **763** comment s . First, consistent with the broad applicability approach, we are finalizing the percentage electric sales and natural gas - use thresholds as subcategor ization criteria instead of as applicability criteria. In addition , for non - CHP combustion turbines, we are eliminating the proposed 219,000 MWh total electric sales criterion. Finally, we are eliminating the proposed “constructed for the purpose of” quali fier for the total and percentage electric sales criteri a . We are also not finalizing CO 2 standards for dedicated non
- fossil fuel
- fired or industrial CHP combustion turbines. The rationale for not finalizing CO 2 standards for dedicated non
- fossil and indus trial CHP units is discussed in more detail in section III. The EPA agrees with commenters that the NSPS applicability framework should be structured so that permitting authorities , the regulated community , and the public can determine what standards apply prior to a unit having commenced construction. With this in mind, the EPA has concluded that the proposed fossil fuel
- use, natural gas - use, percentage electric sales , and total electric sales applicability criteria for combustion turbines are not ideal approaches . Because applicability 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 operators would***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **484** of **763** not know the extent of their comp liance obligations until after the compliance period. Further, from a practical implementation standpoint, existing permitting rules generally require pre
- construction permitting authorities to include enforceable conditions limiting operations such that unaffected units will not trigger applicability thresholds. Such conditions are often called “avoidance” or “synthetic minor” conditions, and these conditions typically include ongoing monitoring, recordkeeping, and reporting requirements to ensure that operations remain below a particular regulatory threshold. The following sections provide further discussion of the final general applicability criteria and the rationale for changing certain proposed applicability criteria to subcategorization criteria.
a. Base load rating criterion. We are retaining the applicability criteri on that a combustion turbine must be capable of combusting more than 260 GJ/h ( 250 MMBtu/h ) heat input of fossil fuel. We revised the proposed 73 MW form of the base load rating criterion to 260 GJ/h because some commenters misinterpreted the 73 MW form (which is mathematically equivalent to 250 MMBtu/h) as the electrical output rating of the generator. This change is a non
substantive unit conversion intended to limit misinterpretation.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **485** of **763** While some commenters suggested that we expand th is applicability criteri on to cover smaller EGUs as well, 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 identify an appropriate BSER for these units , we are not finalizing CO 2 standards for smaller units. b. Total Electric Sales Criterion . The proposed 219,000 MWh total annual sales criterion wa s based on a 25 MW unit operating at base load the entire year (i.e., 25 MW * 8,760 h/y = 219,000 MWh/y). This criteri on was included in the original subpart Da coal - fired EGU criteria pollutant NSPS . Coal - fired EGUs tend to be much larger than 25 MW, and the cri terion’s primary purpose was to exempt industrial CHP facilities from the criteria pollutant NSPS. In the context of combustion turbines, however, c ommenters expressed 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 instead of a single , larger , more - efficient simple cycle turbine. The reason for this is that the 219,000 MWh threshold would allow smaller simple cycle combustion turbines of less than 80 MW to sell significantly more electricity relative to their potential electric output than larger turbines. Many commenters also***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **486** of **763** indicated that having the flexibility to operate a simple cycle turbine at a higher capacity factor is important because 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 combustion turbines. Instead, we are finalizing a criterion that will exempt combustion turbines that do not have the ability to sell at least 25 MW to the grid . This approach will maintain our goal of exempting smaller EGUs , while avoiding the perverse environmental incentive s mentioned by the commenters. As expl ained in Section III , however, industrial CHP units are sized based on demand for useful thermal output, so there is less of an incentive for owners and operators to install multiple smaller units . Therefore, we are maintaining the 219,000 MWh total electr ic sales criterion for CHP units.
c. Percentage Electric Sales Criterion . Commenters generally opposed the proposed percent age electric sales criterion approach because it was based in part on actual electric sales , meaning applicability could change periodically (i.e., a unit’s electric sales may change over time, rising above and falling below the electric sales threshold) . The EPA agree s this situation is not ideal . T o avoid situations in which applicability changes from year to year , we first considered two approaches using permit restrictions . Under***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **487** of **763** the first approach, a standard would apply to all sources with permit restriction s mandating electric sales above a threshold (i.e., an approach that closely mirrors the proposed percentage electric sales criterion) . Under the second approach, a standard would apply to all sources without permit restriction s limiting electric sales to a level below that threshold (i.e., effectively identifying non -base load units and excluding them from applicability) . As stated in the proposal, we did not think it was critical to include peaking and cycling units because [extract language from proposal preamble] . The first approach i s not practical , however, because new combustion turbines could avoid applicability by simply 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 requisi te amount of electricity. This would be nonsensical , especially because system demand would not always be sufficient to all ow all permitted units to operate above the threshold. Therefore, we rejected the first permitting approach . In contrast , the second approach would be a viable method for identifying and exempting peaking units from applicability . However, there are multiple drawbacks to such an applicability approach . First, this approach would subject those turbine s without a permit restricting electric sales to the final***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **488** of **763** emission standards , which raises concerns as to whether turbines with lower actual sales could achieve the standards . For example , new NGCC units tend to dispatch prior to older existing units and will generally operate for extended periods of time near full load and sell electricity above the percentage electric sales threshold. However, as NGCC units age , they tend to start and stop more frequently and operate at part load. Yet, even if these units sell below the percent age electric sales threshold , they would still be affected units if they did not take a permit restriction . As commenters noted, part - load operation and frequent starts and stops can reduce the efficiency of a combustion turbine . While we are confident that our final standards for natural gas
- fired base load combustion turbines can be achieved by units serving either base or intermediate load, we are not as confident that affected NGCC units that might someday be operated as non -base load units (e.g., as NSPS units age their incremental generating costs will tend to be higher than newer units and they will dispatch less) could achieve the standards. Mo re importantly , however, we are concerned that using a permitting approa ch for the percentage electric sales criterion would create problems due to the interaction between 111(b) and 111(d) . The EPA cannot finalize emission guidelines for existing sources under 111(d) unless the EPA has promulgated emission***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **489** of **763** 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 the se low- electric sales units would generally be simple cycle combustion turbines and the high
- electric sales units would generally be NGCC combustion turbines, this would not always be the case. In contrast, we are finalizing an applicability approach in the 111 (d) emission guidelines that is based on a combustion turbine ’s design characteristics rather than electric sales . Simple cycle combustion turbines are excluded from applicability, while NGCC units are included. As a result, the universe of sources covered by the 111(b) standards would not necessarily be the same universe of sources covered by the 111(d) standards. To resolve this issue, we considered whether we could change the 111(d) applicability criteria to be based on historical operation rather than design characteristics. For example, if an existing combustion turbine had historically sold less than one - third of its potential output to the grid, then it would be exempt from the emission guidelines. However , many existing NGCC units have historically sold less than this amount of electricity, meaning that they would not be subject to the rule. We ran into similar issues when considering other***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **490** of **763** thresholds. For example, a percentage electric sales threshold of 10 percent would still exempt roughly 5 percent of existing NGCC units from 111(d) , while simultaneously raising achievability concerns with the 111(b) standard. Moreover, even if we had finalized 111(d) applicability criteria based on historical operations, existing NGCC units could have decided to take a permit restriction limiting their electric sales going forward to avoid applicability. Under any of these scenarios, our goals with respect to 111(d) would not be accomplished. To avoid this result , the EPA has concluded that it is appropriate to fi nalize the broad applicability approach and set standards for combustion turbines regardless of what percentage of their potential electric output they sell to the grid . To accommodate the continued use of simple cycle and fast
- start NGCC combustion turbines for peaking and cycling applications , however, the EPA has subcategoriz ed natural gas - fired combustion turbines based on a variation of the proposed percentage electric sales criterion. Specifically, and as explained in more detail in S ection IX.B, we are finalizing the sliding
- scale approach on which we solicited comment . d. Natural gas - use criteri on . Similar to the proposed electric sales criteria, commenters generally opposed the proposed natural gas - use criteri on being based on actual operating parameters. As with the electric sales***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **491** of **763** criteria, the EPA agrees that applicability that can switch periodically due to operating parameters is not ideal. The EPA evaluated two approaches for implementing the intent of the p roposed natural gas - use criteri on (i.e., to exclude non - natural gas - fired combustion turbines ) through operating permit restrictions . Under the first approach, an emission standard would apply to all combustion turbines with a permit restriction mandating that natural gas contribute over 90 percent of total heat input . 532 Under the second approach, an emission standard would apply to all combustion turbines without a permit restriction limiting natural gas use to 9 0 percent or less of total heat input . 533 As with the percent age electric sales criterion , the first approach is not practical because combustion turbines could avoid applicability by simply not having a permit that requires the use of more than 90 percent natural gas, even if they intend to only burn natural gas . We disregarded this approach because it would essentially provide a

532 This approach could also be written as “ an emission standard would apply to all combustion turbines with a permit restriction limiting the use of non
- natural gas fuels to 10 percent or less of the total heat input.” Applicability could then be avoided by simply being permitted to burn non
- natura l gas fuels for more than 876 hours per year even if they actually intended to seldom, if ever, combust the alternate fuels . 533 This approach could also be written as “ an emission standard would apply to all combustion turbines without permit restrictions mandating that non
- natural gas use contribute over 10 percent or more of total heat input.”***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **492** of **763** pathway for all NGCC units to avoid applicability under both 111(b) and 111(d). The second approach is problematic because operating permit restrictions to improve air quality are typically written to limit high emission activities (e.g., limiting the use of distillate oil to 500 hours annually), not to limit lower emitting activities. This approach cou ld lead to perverse environmental impact s by incentivizing the use of non
natural gas fuels, which would typically result in higher CO 2 emissions. Furthermore, the second approach would not limit the fuels that can be burned by affected units (i.e., combus tion turbines not required to use non
- natural gas fuels) and would continue to cover combustion turbines even when they burn over 10 percent non

–natural gas fuels. Because all non - natural gas fuels except hydrogen have CO 2 emission rates higher than natura l gas , this approach would exacerbate the concerns raised by commenters about the achievability of the 111(b) requirements when burning backup fuels. In light of these issues, the EPA has concluded that permit restrictions are not an ideal approach to distinguish ing between natural gas - fired and multi
- fuel - fired combustion turbines and are finalizing a variation of the broad applicability approach. The EPA has concluded that the only practical approach to implement the natural gas
- use criteri on is to lo ok at the turbine’s physical ability to burn natural gas. Therefore, we***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **493** of **763** are not finalizing CO 2 standards for combustion turbines that are not capable of firing any natural gas (i.e., not connected 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 combustion turbines that are built in remote or offshore locations without access to natural gas. Consistent with the broad applicability approach,
we are finalizing standards for all other combustion turbines, but are subcategorizing between natural gas
- fired turbines and multi
- fuel - fired turbines. Specifically, and as explained in more detail in Section IX.B, we are distinguishing between these classes of turbines based on whether they burn greater than 90 percent natural gas or not. B. Subcategories This section describes comments we received regarding the proposed size
-based subcategories and our rationale for not finalizing them. In addition, it describes comments we received regarding operations
-based subcategories, such as base load and peaking units; our rationale for adopting operations
-based subcategories; and the appropriate thresholds to distinguish between such subcategories. Finally, it describes comments we received regarding fuel
-based subcategories and our rationale for adopting fuel
-based subcategories. We are finalizing a variation of the broad applicability approach where the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **494** of **763** percent age electric sales and natural gas - use criteria serve as thresholds that distinguish between s ubcategor ies of combustion turbines . 1 . S ize
-based Subcategories At proposal, the EPA identified two size
-based subcategories: (1) large natural gas
- fired stationary combustion turbines with a base load rating greater than 850 MMBtu/h and (2) small natural gas
- fired stationary combustion turbines with a base load rating of 850 MMBtu/h or less. The EPA received numerous comments regarding our proposal to subcategoriz e combustion turbines by size. Some commenters agreed with the 850 MMBtu/h cut -point between large and small units, some suggested increasing it to 1,500 MMBtu/h, and others suggested eliminating size
-based subcategorization altogether . For example, s ome commenters stated that the 850 MMBtu/h cut -point was inappropriate because it was originally calculated based on NOX performance , not CO 2 performance . These commenters stated that 850 MMBtu/h was not a logical demarcation between more efficient versus less efficient combustion turbines , but rather would divide the units into arbitrary size classification s . These commenters suggested that 1,5 00 MMBtu/h would be a better cut point because (1) based on data reported to Gas Turbine World , new combustion turbines are not currently offered with a heat input rating between 1,300 MMBtu/h and 1,800 MMBtu/h and (2)***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **495** of **763** this cut
-point more accurately reflect s when more efficient technologies are available . In contrast, other commenters said that differentiation between small and large combustion turbines was not justified at all because many of the same efficiency technologies that reduce the emission rates of larger units could be incorporated into smaller units (e.g., increase the turbine engine operating temperature, increase the turbine engine pressure ratio, and using multi
-pressure steam and a steam reheat cycle) . These
commenters also said that s eparate standards for small and large turbines would undermine the incentive for technology innovation, which they described as a key purpose of the NSPS program, and that relaxing standards for smaller units will discourage investment in more efficient te chnologies , 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 decided not to subcategoriz e combustion turbine s 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. 534

534 Duct burners are optional supplemental burners located in the HRSG that are used to generate additional steam. Heat input to duct burners could in theory be twice that of the combustion***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **496** of **763** However, since 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 the heat input data for existi ng NGCC units that has been submitted to the EPA Clean Air Markets Division . These data include the heat input from duct burners and show that multiple NGCC power blocks have been built in the past with heat input capacities that fall within the range that commenters suggested. Therefore, the EPA has concluded that the regulated community uses various sizes of NGCC turbines and when the heat input from duct burners is included , there is no absolute clear break between size s of NGCC units that could distinguishes between small and large units . In fact , s ubcategorizing by size could unduly influence the development of future NGCC offerings because manufacturers could be incentivized to design new products at the top end of the small subcategory to take advantage of the less stringent emission standard . Second , commenters suggested that a cut -point of 1,500 MMBtu/h reflects when more efficient technologies become available. However, when we reviewed actual operating data , we only found a relatively weak correlation between turbine size turbine engine, but are more commonly sized at 10 to 30 percent of the heat input to the combustion turbine engine.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **497** of **763** and CO 2 emission rate s and did not see a dramatic drop in CO 2 emission rate s at 1,500 MMBtu/h. In addition , the variability of emission rate s among similar size units far exceeds any difference that could be attributed to a differen ce in size . Finally, the EPA has concluded that, while certain smaller NGCC designs are less efficient than larger NGCC designs, multiple existing small units have demonstrated emission rates below the range of emission rates on which we solicited comment. We have concluded that the lower design efficiencies of 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 have comparable efficiencies to large NGCC units . Specifically, manufacturers could improve the efficiency of the turbine engine by using turbine engines with higher f iring temperatures and high compression rat i os and could improve the efficiency of the steam cycle by switching from single or double
-pressure steam to triple
-pressure steam and adding a reheat cycle . Our rationale for setting a single standard for small and large combustion turbines is explained in more detail in Section IX.D below. 2 . S ales -based Subcategories As described in the applicability section, the final applicability does not include exemptions for non
- CHP units based on either actual electric sales or permit restrictions***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **498** of **763** limiting the amount of electricity that can be sold. This section describes the comments we received regarding subcategorizing based on percent electric sales, our response to those comments, and the final percent electric sales subcategorization. Numerous commenters supported three sales -based subcategories for peaking, cycling/ load- following /intermediate, and base load units. These commenters said that each of the three subcategories should be distinguished by annual hours of operation and that each should have a different emission standard. In general, these commenters suggeste d that the BSER for peaking units should be simple cycle combustion turbines, the BSER for the middle category should be high
- efficiency aeroderative simple cycle or fast - start NGCC combustion turbines , and the BSER for base load units should be highly efficient NGCC combustion turbines . Other commenters opposed the tiered approach. These
commenters s aid that separate standards for different operating conditions would be complicated to implement and enforce, while providing few benefits . These commenters said that a tiered approach could 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 that would operate under the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **499** of **763** percent age electric sales threshold instead of higher
- capital
cost, more - efficient units that would operate above the threshold. They added that 12
- operating
-month capacity factors vary significantly for both simple cycle and NGCC combustion turbines . These commenters stated that real -world variability and uncertainty significantly diminishes the value of creating tiered standards for peaking and load
- following units because individuals responsible for long
- range decisions related to reliability may react to a system of tiered standards by purchasing additional generating assets to ensure system demand can be satisfied while operating individual units below tier
specific percent age electric sales thresholds. After evaluating the se comments, the EPA has concluded that it is appropriate to adopt a two - tiered subcategory approach based on a percentage electric sales threshold to distinguish between non -base load (e.g., peaking, cycling, and intermediate/load
- following units ) and base load units. While multiple commenters support ed a three - tiered approach, 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **500** of **763** output -based standard for other than non -base load and base load subcategor ies . 535 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 peaking units , low capital costs and the ability to start and stop quickly to meet increased demand are key . Simple cycle combustion turbines meet these criteria and thus comprise the bulk of peaking units. In contrast, for base load units , efficiency is the key consideration , while capital costs and the ability to start and stop quickly are less important . While NGCC units have relatively high capital costs and are less flexible operationally , they are more ef ficient than simple cycle units. NGCC uni ts recover the exhaust heat from the combustion turbine with a HRSG to power a steam turbine , which reduces fuel use and CO 2 emission s by 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 rate s as NGCC combustion turbines and because they serve a different primary
535 We have concluded it is not possible to identify appropriate subcategorization criteria for cycling, load
- following, or intermediate load units. The broad non
-base load and base load subcategories include these units.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **501** of **763** role , we have concluded that it is appropriate to distinguish between the non -base load and base load subcategories in a way that recognizes the distinct roles of the different turbine designs on the market . The challenge, however, is setting a threshold that will not distort the market. The future role of dedicated peaking units is unclear. For example, some commenters indicated that increased generation from intermittent renewable sources has created a perceived need for additional cycling generation that will operate between the traditional roles of peaking and base load units. As stated above , simple cycle combustion turbines historically have served peak demand, while NGCC combustion turbines have operated at base load. The need to back up intermittent renewables has blurred this distinction. For example, some manufacturers have developed high efficiency simple cycle turbines. These high efficiency turbines have higher capital costs than older simple cycle turbine designs, but maintain similar flexibilities (e.g., ability to start 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 efficiencies than base load NGCC designs, 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **502** of **763** and fast - start NGCC units can be used for traditional peaking applications, as well as higher capacity applications, such as supporting the growth of intermittent renewable generation. Importantly, these newer technologies are both significant 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 attempted to identify a potential percent age electric sales threshold for natural gas - fired non -base load units. To do this, we evaluated the annual electric sales of existing simple cycle combustion turbines from the period of 2005 to 2014. We tri ed to identify a threshold that would be high enough to subcategorize the majority of simple cycle turbines operating at historical capacities, yet low enough to avoid including high efficiency simple cycle units and fast
- start NGCC units in this subcatego ry . We also tried to avoid setting a threshold that would create a perverse incentive for owners and operators to avoid applicability by installing multiple, less efficient turbines instead 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 commenters***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **503** of **763** objected to the proposed one
- third electric sales threshold, so few, if any, owners or operators would consider a 10 percent threshold sufficiently flexible to accommodate new peaking and cycling units . In addition, our cost models show that 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 per cent for non -base load units. Ninety
- eight percent of existing simple cycle turbines did not exceed this level of sales between 2005 and 2014. In addition, at this level 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 simple cycle units that had electric sales in excess of 25 percent were operating during a system emergency, meaning some of those sales would not count towards determi ning exceedance of the threshold . This level is further supported by the permit restriction for the CPV Sentinel facility in Desert Hot Springs, California. This facility consists of eight high
- efficiency intercooled simple cycle turbines intended to suppo rt wind generation in California. Each unit at this facility is restricted to 2,500 hours of operation annually. Assuming an average duty cycle of 90 percent, this is equivalent to an annual percentage electric sales restriction of approximately 25 percent .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **504** of **763** Similar to the 10 percent threshold, however, the EPA acknowledges that owners and operators of new simple cycle turbines would generally not elect to avail themselves of a 25
- percent sales restriction for multiple reasons. First, many commenters stated that existing simple cycle turbines are permitted to operate 2,920 hours or more annually to respond to variable annual demands and provide capacity reserve in the event of a system emergency. The commenters stated that , due to the changing nature of the grid (e.g., increased generation from intermittent renewable generation), these needs will increase in the future. Additionally, the EPA has concluded that 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 emission standards that have been placed on individual units. By limiting non -base load units to less than 25 percent of their potential electric output before the base load st andard would take effect , utilities and other developers could decide to build multiple , lower - capital
- cost, less - efficient simple cycle rather than fewer , higher
- capital
- cost, more - efficient simple cycle or fast
start NGCC units . The overall CO 2 emissions ( and the cost to ratepayers ) would be higher for a scenario with multiple combustion turbines operating at lower loads than a scenario with fewer, more efficient units.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **505** of **763** Based on concerns raised in comments about the impact of intermittent renewable generation (e.g., wind and solar) 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 536 would exceed the proposed one - third percentage electric sales threshold based on historical operation. We also examined the operation of simple cycle turbines in the lower 48 states between 2005 and 2014 using information submitted to the EPA Clean Air Markets Division. Finally , we reviewed the recent operati ng history of simple cycle turbines in regions with relatively large amounts of wind and solar generation. In the proposal, the EPA estimated the number of existing simple cycle turbines that would have exceeded the proposed one third percentage electric sales threshold (i.e., 33.3 percent) by looking to see whether they operat ed over 2,920 hours in any given year. However, this method overestimated the number of simple cycle turbines that would have exceeded the threshold in two ways. First, it did not account for hours in which simple cycle turbines were operating at part load. The typical duty cycle (i.e., average capacity factor while operating) of simple cycle turbines is approximately 70 percent. Therefore, simple
536 We are using simple cycle turbine operation to approximate the operation of all peaking units.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **506** of **763** cycle turbines can operate in excess of 2,920 hours and still not sell one - third of their potential electric output to the grid . Historically, simple cycle turbine s 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 sales exceeded one - third of their potential electric output. Second, we proposed to calculate the percentage electric sales criterion on a 3
-year rolling average basis. Using a 3
- year rolling average, only two existing simple cycle turbines historically sold enough electricity to exceed the proposed one - third percentage electric sales threshold. We used information reported to the Energy Information Administration (EIA) to determine the impact of renewable generation on the operation of simple cycle 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 availabl e from 2008 through 2012. Specifically, we examined data from the Southwest Power Pool (data approximated by EGUs in Nebraska, Kansas, and Oklahoma), Texas, and California , all of which had increases for the percent of wind and solar electricity generated in
- state and percent of total electric generation from wind and solar from 2008 through 2014. To determine the impact , if any, of the increased generation from intermittent renewable s ources on***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **507** of **763** simple cycle turbine capacity factors , the EPA reviewed data submitted for simple cycle turbines to the EPA’s Clean Air Markets Division (CAMD) over the same time period. (i) Southwest Power Pool . The percent 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 wind and solar was 28 percent, while overall electricity demand grew 1 percent annually on average. Based on statements in some of the comments, we would expect to see a large change in the operation of simple cycle turbines in this region. However, the average electric sales from simple cycle turbines only increased at an annual rate of 1.7 percent, and remained essentially unchanged at 3 percent of potential electric output between 2008 and 2014. Overall, generation from simple cycle turbines in the Southwest Power Pool increased slightly more at an annual rate of 2.5 percent, resulting from additional simple cycle capacity being in line with what was expected due to overall increased electricity demand. The lack of significant change in the operation of simple cycle turbines in this region could be explained by the relatively large amount of exported power. If most of the intermittent power wa s being exported, the intermittent nature of the power would primarily impact other transmission regions. An alternate explanation is that other generating assets are flexible enough to respond to***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **508** of **763** the intermittent nature of wind generation and that simple cycle turbines are not necessary to backup wind and solar generating assets to the degree some commenters suggested. If this were the case, then new simple cycle turbine will primarily continue to fill their historical role as peaking units and flexible combined cycle units will provide the primary backup capacity for new wind and solar generating assets. (ii ) Texas . The percent of in
- state generation from wind and solar in Texas increased from 4 to 9 percent between 2008 and 2014. The average growth rate of wind and solar was 13 percent, while the overall demand grew an average of 2 percent annually. Similar to the Southwest Power Pool, the overall percent of electric sales relative to the potential electric output from simple cycle turbines has remained relatively unchanged. Average electric sales relative to potential electric output from simple cycle turbines actually decreased at an annual rate of 1.1 percent. However, the overall generation from simple cycle combustion turbines increased at an annual rate of 6.6 percent, resulting from simple cycle capacity additions occurring at approximately four times what would be expected from growth in overall demand. The EPA has concluded that the most likely simple cycle turbines to support intermittent renewable generation are the most efficient simple cycle combustion turbines installed in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **509** of **763** particular transmiss ion region. There are two highly efficient intercooled simple cycle turbines installed in Texas. These two combustion turbines sell an average of 10 percent of their potential electric output annually, compared to an average of 3 percent for the remaining simple cycle turbines. No simple cycle turbine in Texas sold more than 25 percent of its potential electric sales annually. This growth in simple cycle turbine capacity could indicate that the additional generation assets are providing firm capacity for intermittent generation sources such as wind and solar, but based on the data those 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. (iii) Californ ia . The percent 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 the other evaluated regions. Average electric sales relative to potential electric output from simple cycle turbines increased from 5.1 to 5.9 percent, an annual rate increase of 4.5 percent. As i n Texas, considerable additional simple cycle capacity has been added in recent years. The average capacity of simple cycle turbines is increasing at 15***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **510** of **763** percent annually even though overall demand has remained relatively steady. In addition, the newest simple cycle turbines are operating at higher capacity factors than the existing fleet of simple cycle turbines, resulting in an average increase in generation from simple cycle turbines of 21 percent. Many of the new additions are intercooled simple cycle tu rbines that may have been installed with the specific intent to back up wind and solar generation. The annual electric sales relative to the potential electric output for the intercooled turbines range from 3 to 25 percent, with a 7 percent average. No simple cycle turbines in California have sold more than one
- third of their potential electric output on an annual basis. The operation of simple cycle turbines that existing prior to 2008 have not changed significantly. Average electric sales relative to pot ential electric output for these simple cycle turbines increased at an annual rate of 0.1 percent. This is an indication that support for additional renewable generation is being provided by new units and not by the installed base of simple cycle units. These units are still serving their historical role of providing power during peak periods of demand. Based on historical amounts of intermittent generation, the proposed percentage electric sales threshold would appear to offer sufficient operational flexibility for new peaking (i.e . ,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **511** of **763** simple cycle) combustion turbines. Existing NGCC units , other generation assets, and demand response programs are currently provi di ng adequate backup to renewable generation. In the future, however, existing NGCC units will likely operate at higher capacity factors. They will therefore be less available to provide backup power for intermittent generation. In addition, the percent of power generated from intermittent sources is expected to increase in the future. Both of these factors could require additional flexibility from the remaining generation sources to maintain grid reliability. When attempting to determine an emission rate for units actually providing this middle tier of service strictly based on technology, we have concluded there is significant overlap . In addition, we do not have specific cost information on either high efficiency aeroder ivative turbines or rapid start combined cycle units relative to conventional simple cycle or combined cycle un its so we cannot take cost effectiveness into account. Regardless, as described earlier, for combustion turbines operating above this threshold it is cost effective and the BSER is the addition of heat recovery to the turbine exhaust. Further, the EPA has concluded that even if we were able to establish an appropriate technology based BSER subcategorization, we do not have sufficient information to establish an appropriate emission standard for a middle tier***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **512** of **763** category. For example, in the transition from peaking to base load operation (i.e., cycling and intermediate load ) , combustion turbines may have similar percent electric sales, but their operating characteristics can differ significantly. For example, though they may have similar annual percent elec tric sales, one unit might have relatively steady operation (i.e., less starts and stops and more operation near full load) and the 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 installed. Taking these considerations into account, the EPA has concluded that we do not have sufficient information at this time to establ ish an appropriate emission standard for a middle tier subcategory. Even though fast start combined cycle technologies, reciprocating internal combustion engines, energy storage technologies, and demand response programs are promising technologies for providing backup power for renewable generation, none of them historical ly have been deployed in sufficient capacity to provide the potential necessary capacity to facilitate the continued growth of renewable generation. While we anticipate that state and federally issued permits for new electric generating sources will consider the CO 2 benefits of these technologies compared to simple cycle turbines, the EPA***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **513** of **7 63**  has concluded at this time it is appropriate to finalize an NSPS that provides additional flexibility for new non -base load combustion 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, we concluded that a trigge r based on the 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 efficiency of the unit. The EPA has concluded that this approach provides sufficient operational flexibility for new non -base load (i.e., simple cycle and fast response combined cycle) combustion 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
- specific net efficiency promo tes installation of the most efficient generating technologies since operational flexibility will be directly linked to the efficiency of the unit . The design net efficiencies for currently available potentially impacted aeroderivative simple cycle combustion turbines range from approximately 32 percent for smaller designs to 39 percent for the largest i ntercooled designs. The***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **514** of **763** efficiencies of industrial frame units range from 30 percent for smaller designs to 36 percent for the largest units. These efficiency values follow the methodology the EPA has historically used and are based on the higher heating value (HHV) of the fuel. In contrast, combustion turbine vendors in the United States often quote efficiencies based on the lower heating value (LHV) of the fuel. The LHV of a fuel is determined by subtracting the heat of vaporization of water vapor generated during combustion of fuel from the higher heating value. For natural gas, the LHV is approximately 10 percent lower than the HHV. Therefore, the corresponding LHV efficiency ranges would be 35 to 44 percent for aeroderivative designs and 33 to 40 perce nt for frame designs. We considered basing the electric threshold on both the higher and lower heating value efficiency. The EPA typically uses the higher heating value, but in light of comments expressing uncertainty in the operation of non -base load uni ts in the future, we opted to be conservative and use the lower heating value efficiency. During the next review of the EGU GHG NSPS, the EPA anticipates that fast
- start/rapid
- response combined cycle technologies, energy storage technologies, and demand re sponse programs will be further developed, and we will
re - evaluate lowering the percent electric sales threshold.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **515** of **763** Based on comments, we anticipate the aeroderivative simple cycle and fast - start NGCC turbines will make up the majority of new combustion turbines intended for non -base load use (e .g ., peaking) applications. Based on the sliding scale threshold approach, owners/operators of new simple cycle combustion turbines would be able to sell between 35 to 44 percent of the potential electric output to avoid complying with the standards in this rulemaking. Based on historical operation of simple cycle turbines, 99.5 percent do not sell more than one
- third of their potential electric output on an annual basis. Therefore, the majority of new simple cycle app lications would not be significantly impacted how they would operate absent the requirements of this rulemaking. In addition, 99.9 percent of simple cycle turbines operate less than 36 percent on an annual basis. Owners/operators of new simple cycle combu stion turbines would still have multiple technology options available to them to accommodate 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 locat ed in Montana and New York respectively. As noted earlier, the most efficient simple cycle turbine is 44 percent efficient and would accommodate operation of the Montana facility. The only simple cycle turbine that exceeded the maximum allowable percentage electric sales threshold, based on***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **516** of **763** 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 the incremental generation due to the emergency would not have been counted against the total electric sales subcategorization threshold . We are capping the total 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. Though combined cycle unit design efficiencies often exceed 50 percent, the EPA has concluded that the emission rate is relatively steady above this level of electric sales, and there is no reason that the same output based standard should not apply. Second, the design net efficiency of the flexible combined cycle unit intended as an option for peaking and intermediate load applications is 49 percent. As described earlier, this technology can serve the same purpose as high efficiency aeroderivative simple cycle turbines. Setting a cap any lower than 50 percent could have the perverse impact of incentivizing the installation of less efficient technologies. As mentioned previously, the EPA solic ited comment on excluding electricity sold during system emergencies as counting toward percent electric sales threshold. We have concluded that***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **517** of **763** the emergency conditions exemption provides flexibility to maintain system reliability and minimizes overall co sts to the sector. We disagree with commenters 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 provides certainty for the regulated community, public, and regulatory authorities on applicability of the emission standards. System emergencies are defined 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 that electricity sold during hours of operation when the unit is called upon to operate due to a system emergency will not be counted toward the percentage electric sales threshold. The applicable emiss ion standard during these periods would be the same standard that would otherwise apply (i.e., a heat input based standard for peaking and multi
- fuel - fired units and an output based standard for natural gas - fired base load units). Electric sales from units that are not called upon to operate specifically due to the system emergency (e.g., units already operating when the system emergency is declared) would be counted against the total percentage electric sales threshold.
c . Fuel -based Subcategori es***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **518** of **763** As described in the applicability section, we are finalizing a version of the "broad applic ability approach . " Under the broad applicability approach, the EPA solicited comment on a subcategorization approach based in part on natural gas - use. We received few comments on this approach . One of the comments we did receive was that combustion turbines that burn fuel s other than natural gas have higher CO 2 emission s due to the higher relative carbon content of alternate fuels. Besides hydrogen, 537 natural gas has the lowest CO 2 emission rate on a lb/MMBtu basis of any fossil fuel. Therefore, burning fuels other than natural gas will 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 that burn non
- natural gas fuels should receive a less stringent emission standard. For the reasons described in the applicability section, we have decided to set emission standards for all combustion 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, as commenter s explained, mu lti
- fuel - fired combustion turbines cannot achieve the emission standards achieved by natural
- gas fired turbines.

537 Hydrogen would only be considered a fossil fuel if it were derived for the purpose of creating useful heat from co al, oil, or natural gas.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **519** of **763** For this reason, it would not be reasonable to require affected EGUs to comply with a standard based on the use of natural gas during periods when significant quantities of non
- natural gas fuels are being burned. If we did not subcategorize, owners and operators would not be able to combust other fuels in their turbines, i ncluding process gas, blast furnace gas, and petroleum-based liquid wastes, which might otherwise be wasted. In addition, without the ability to burn backup fuels 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 distinguish between this subcategory and the natural gas
- fired subcategories, we are using the same threshold as proposed. Specifically, c ombustion turbines that burn ninety percent or less natural gas on a 12
- month rolling average basis will be included in this subcategory and subject to a separate emission standard, which is discussed in Section IX.D. C. Identification of the Best System of Emission Reduction This sec tion summarizes the EPA’s proposed BSER determinations for stationary combustion turbines, provides a summary of the comments we received, and explains our final BSER determination s for each of the three subcategories we are now finalizing . For natural gas - fired stationary combustion turbines operating as base load units, we proposed and are finalizing the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **520** of **763** use of NGCC technology as the BSER . For the other two subcategories of affected combustion turbines

– non -base load natural gas - fired combustion turbi nes and multi
- fuel - fired combustion turbines

– we are finalizing the use of clean fuel s
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 aeroderivative turbines , and ( 3 ) modern, efficient NGCC turbines . We rejected partial CCS as the BSER because we concluded that we did not have sufficient information to determine whether implementing CCS for combustion turbines was technically feasible . We rejected high
- efficiency simple cycle aeroderivative turbines as the BSER because this standalone technology does not provide emission reductions and generally is more expensive than NGCC technology for base load applications . In contrast, NGCC is the most common type of new fossil fuel
- fired EGU currentl y being planned and built for generating base load power. NGCC is technically feasible , and NGCC units are currently the lowest
- cost, most efficient option for new base load fossil fuel
- fired power generation. After considering the options, the EPA proposed to find that modern, efficient NGCC technology is the BSER for base load natural gas fired combustion turbine s.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **521** of **763** For non -base load natural gas - fired units and multi
- fuel fired units , we did not propose a specific BSER or associated numeric emission standards , but instead solicited comment on these issues. 2. Comments on the Proposed BSER for Base Load Natural Gas - Fired Combustion Turbines [ ADD A SENTENCE OR TWO HERE AS AN INTRO. ]
a . Partial CCS . Some commenters stated that our proposed BSER analysis for stationary combustion turbines was inconsistent with our proposed BSER analysis for coal - fired units. They stated that the EPA had determined that the use of CCS was feasible 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 . These c ommenters 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 wanted the EPA to reconsider CCS as the BSER for NGCC, many of these commenters
were attempting to prove that if the agency did no t choose CCS as the BSER for NGCC units , then the agency should not for coal fired units either . Some commenters referenced the Northeast Energy Association NGCC plant in Bellingham, MA , which operated from 1991
- 2005 with***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **522** of **763** 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 of financial difficulties, including rising gas prices and discontinuation of tax credits. According to these commenters , this plant provided sufficient proof that CCS technology is adequately demonstrated for NGCC units . Additionally, these commenters referred to other NGCC plants that are planned or in development that will incorporate CCS. The plants mentioned were the Sumitomo Chemical Plant in Japan, the Peterhead CCS project in Scotland, and the GE - Sargas Plant in Texas. The Sumitomo Chemical Plant has a base load NGCC unit with CCS operating on an 8 MW slip
- stream that captures about 150 tons of CO 2 per day for commercial use in the food and beverage industry. This carbon capture system has been operating since 1994. The Peterhead CCS project in Scotland is in the planning stages. It is a collaboration between Shell and SSE to provide 320 MW of electricity to its customers 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 GE Sargas Plant in Texas is a planned joint venture that does not currently have a location selected, but is intended to be a base load NGCC unit with CCS used for EOR.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **523** of **763** These commenters also referenced reports authored by DOE, NETL, the Clean Air Task Force (CATF), CCS Task Force, ICF Inc. , and Global CCS Institute suggesting that , because CCS technology for NGCC is included in these reports , it is adequately demonstrated. Some commenters referred to a DOE/NETL study that suggested that the cost of CCS for NGCC units would be more cost - effective than for coal
- fired EGUs. One non - industry commenter emphasized that a technology does not have to be in use to be considered adequately demonstrated. In addition, some commenters disagreed with the EPA’s decision to treat combustion turbines differently than coal
fired units with respect to CCS on the basis that combustion turbines start up , shut down , and cycle load more frequently than coal - fired units. According to the se commenter s , the operating characteristics of combustion turbines do fluctuate, but so do those of coal - fired units. Another commenter 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 system during startup and shutdown modes (which are typically shorter and less intensive efforts compared to the startup or shutdown of a coal facility) and then employ the carbon capture system when operating normally. One commenter stated that most future base load fossil fuel
- fired generation will be NGCC and that not***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **524** of **763** making CCS the BSER for NGCC would result in significant CO 2 emi ssions . Other commenters supported the EPA ’ s determination that CCS is not the BSER for combustion turbines. These c ommenters said that CCS is not adequately demonstrated for combustion turbine s because none are currently operating , under construction, or in the advanced stages of development. They also noted that CCS would have to be demonstrated for the range of facilities included in the regulated source category, which they alleged includes both simple cycle and NGCC units . They specifically noted that the Bellingham , MA demonstration facility was not a full - scale commercial NGCC power plant operating with CCS. These commenters agreed with EPA that CCS do es 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 problem which would only get worse as more renewable energy sources are integrat ed into the grid. These c ommenters added that NGCC units operate differently than coal - fired units because the former start, stop, and cycle frequently , whereas the latter tend to operate at relatively steady loads and do not start and stop frequently . They stated that even if technical barriers could be overcome, the application of CCS to combustion turbines would be more costly (compared to the application of CCS to coal
- fired units)***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **525** of **763** on a dollars -per - ton basis . In addition, these commenters said that other industries’ experience with CCS could not be transfer red to NGCC units due to differences in flue gas CO 2 concentration. Some commenters stated that CAA section 111(a) requires the EPA to account not only for the cost of achieving emission reductions , but also for impact s on energy requirements 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 which represents the best balance of economic, environmental, and energy considerations." 538 The commenters stated that requiring CCS on combustion turbines would adversely affect the nation’s energy needs and the environment because imposing CCS on combustion turbines would invariably delay the emission reductions that can be obtained from new NGCC projects that displace load from older , less efficient generating technologies. In addition , the commenters stated that , because combustion turbines are projected to provide a significant share of new power generation, the EPA should recognize that requiring CCS on these units would have a disproportionally higher impact on electricity prices when compared to the projected number of

538 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981) .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **526** of **763** new coal - fired projects. These commenters concluded that the EPA could not determine that CCS is the BSER for combustion turbines without producing severe and unacceptable consequences for the availability of affordable electricity in the U.S . b . NGCC Turbines Some commenters stated that the proposed BSER analysis should have reflected the emission rates achieved by the latest designs deployed at advanced, state
- of - the - art NGCC installations. These commenters stated that advanced NGCC technologies are the best s ystem for reducing CO 2 emissions with no negative environmental impacts and no negative economic impacts on rate payers. They stated that advanced NGCC technologies are capable of achieving emission rates that are 8 percent lower than conventional NGCC facilities. They also said that the majority of existing sources that do not deploy these advanced technologies are currently ab le to meet the standard and that the proposal failed to explain why these lower
- emitting advanced technologies that are more than adequately demonstrated were not selected as the BSER.
c. Simple Cycle Turbines Many commenters opposed the EPA’s proposal to set emission standards for combustion turbines based on their function rather than based on their design . These commenters stated that the EPA’s determination that NGCC technology is the BSER for base***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **527** of **763** load natu ral gas - fired combustion turbines would apply equally to simple cycle turbines if they sell electricity in excess of the percentage electric sales threshold. They pointed to the word "achievable" in CAA section 111(a)(1) and stated that applying an emission standard based on NGCC technology 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 approach and stated that NGCC t echnology should be the BSER for base - load functions, while simple cycle technology should be the BSER for peak- load functions. 3. Comments on Non -base Load and Multi
- fuel - fired Combustion 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 explained that high efficiency simple cycle uni t s and fast - start NGCC units are actually more efficient when serving non -base load demand than NGCC units that are designed strictly for base load operation. Some c ommenters also suggested that we should subcategorize multi
- fuel - fired combustion turbines, but did not provide any specific technologies that should be considered in the BSER analysis. 4 . Identification of the BSER***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **528** of **763** After our evaluation of the comments and additional analysis , we identi fi ed the BSER for each subcategory of combustion turbine that we are finalizing: base load natural gas - fired units, non -base load natural gas - fired units, and multi
- fuel - fired units.
a. Base load natural gas - fired units . As described in the proposal, we evaluated CCS, NGCC, and high
- efficiency simple cycle combustion turbines as the potential BSER for this subcategory. We selected NGCC as the BSER because it met all the BSER criteria. This section describes our response to issues raised by commenters and our rationale for maintaining that NGCC is the BSER for base load natural gas - fried combustion turbines . (1) Partial CCS . S ome commenters stated that CCS could be applie d equally to both coal - fired and natural gas - fired EGUs . To support this conclusion, the commenters pointed to a retired NGCC -with
- CCS demonstration project , as well as a few overseas projects and projects in the early stages of development . While
we have concluded that these comment er s made strong arguments that the technical issues we raised at proposal could in many instances be overcome, we have concluded that there is not sufficient information at this time for us to determine that CCS is adequately demonstrated for all base load natural - gas fired combustion turbines .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **529** of **763** While the commenters make a strong case that the existing and planned NGCC -with
- CCS projects demonstrate the feasibility of CCS for NGCC units operating at steady state conditions , many NGCC units do not operate this way . For example, the Bellingham , MA and Sumitomo NGCC units cited by the commenters operate d at steady load conditions with a limited number of starts and stops , similar to the operation of coal
- fired boilers. 539 In contrast, our base load natural gas - fired combustion 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 percent of their potential output to the grid. Fast - start NGCC units are designed to be able to start and stop multiple times in a single da y and can ramp to full load in less than an hour. In contrast, coal fired EGUs take multiple hours to start and ramp relatively slowly. These difference s are important because we are not aware of any pilot
- scale CCS project s that have demonstrated how fast and frequent starts, stops, and cycling will impact the efficiency and reliability of CCS . Furthermore , for those

539 As explained in section V. J above, a new fossil fuel
- fired steam generating EGU would, most likely, be built to serve base load power demand exclusively and would not be expected 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
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– Do Not Cite, Quote or Release During Review *** Page **530** of **763** periods in which a NGCC unit is operating infrequently , 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 interval s 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
state operation to make up for those periods when no control is achieved by the CCS , leading to increased costs and energy penalties . While we are optimistic that these hurdles are surmountable , it is simply premature at this point to make a finding that CCS is technically fe asible for the universe of combustion turbines that are covered by this rule . Notably, the Department of Energy has not yet funded 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 demonstration 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. See sections V.E and D. above. One commenter suggested that not having CCS as the BSER for combustion turbines would ultimately halt the development of CCS in the U.S. We disagree. A number of coal - fired power plants are currently being built with CSS, while some existing plants are***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **531** of **763** considering CCS retrofits. Moreover, the NSPS sets the minimum level of control for new sources. We expect that state air agencies and other air permitti ng authorities will evaluate CCS when permitting new NGCC power plants, taking into consideration
case - specific parameters , like operating characteristics, to determine whether CCS could be BACT or LAER in specific instances . While the NGCC -with
- CCS units that currently are in the planning stage s do not provide us with enough assurance to determine that CCS is adequate ly demonstrated for combustion turbines , it is our expectation that these units and others to
come will provide additional information for both permitting 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 improvements to traditional NGCC designs , not a new and unique technology. These incremental improvements include higher firing temperatures in the turbine engine , increasing the number of steam pressures , and adding a reheat cycle to the steam cycle. The emission rates achi eved 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 addition, our review of the operating data for NGCC power blocks installed since 2000 indicates that a unit’s mode of operation in response***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **532** of **763** to system demand (e.g., capacity factor ) affects efficiencies achieved to the extent that we cannot evaluate the impact of particular subcomponents used within the power block. As a result, a conventional NGCC power block located in a region of the country where system demand requires the power block to run continuously at a steady high load can achieve higher efficiencies than an “ advanced” NGCC power block located in a region where system demand requires the power block to cycle on and off to match system demand. For this reason , our data set included a large population of technologies and load conditions to ensure that new NGCC power blocks can achieve the final emission standards in all regions of the country. As we explained in the proposal, NGCC technology meet s 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 units reduce emissions because they have a lower CO 2 emission rate than simple cycle units . Finally, selecting NGCC as the BSER will promote the development of new technology, such as the incremental improvements advocated by the commenters, which will further reduce emissions in the future. Some comment er s suggested that the costs and efficiency impacts of startup and shutdown events are higher for NGCC units***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **533** of **763** than for simple cycle units. Consequently, we refined the LCOE costing approach used at proposal by adding these additional costs and efficiency impacts to our cost comparison . Even accounting for these new costs and impacts , we found that NGCC technology results in a lower cost of electricity than simple cycle technology when a unit’s electric sales exceed approximately one
- third of its potential electric output . The final percentage electric sales criteri on for the base load natural gas - fired combustion turbine subcategory is based on the sliding scale. This means that the dividing line between the base load subcategory and the non -base load subcategory will change depending on a unit’s nameplate design efficiency. For a conventional simple cycle turbine, the base load subcategory will begin at around 33 percent electric sales, while for a newer fast - start NGCC turbine, the base load subcategory will begin at approximately 50 percent electric sales . Anywhere 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 c ommenters mistaken ly thought that the EPA proposed to require some simple cycle combustion turbines to meet an emission standard of 1,000 lb***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **534** of **763** CO 2 /MWh
- g , a level that they assert is unachievable . On the contrary, the EPA is not finding that NGCC technology and a corresponding emission standard of 1,000 lb CO 2 /MWh
- g is the BSER for simple cycle turbines. Instead, the EPA is finding that NGCC technology is the BSER for base load turbine applications. This
means that if an owner or operator wants to sell more electricity to the grid than the amount derived from a unit’s nameplate design efficiency calculated as a percentage of potential electric output, then the owner or operator should install a NGCC unit. If the owner or operator elects to install a simp le cycle turbine instead, then the practical effect of our final standards will be to limit the electric sales of that unit so that it serves primarily peak demand, not to subject it to an unachievable emission 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, including partial CCS, high
- efficiency NGCC technology designed for base load applications , fast - start NGCC, high
- efficiency simple cycle units (i.e., aeroderivative turbines) , and clean fuels . For each of these technologies , we considered technical feasibility, costs , energy and non - air quality impacts, potential for emission reduction s , and ability to promote technology.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **535** of **763** While CCS would result in emission reductions and promot e the development of new technology, we concluded that CCS does not meet the BSER criteria because the low capacity factor s and irregular operating patterns (e.g., frequent starting and stopping and operating at part load) of non -base load units make the technical challenges associated with CCS even greater than those associated with base load units. In addition, because the CCS system would remain idle for much of the time while these units are not running, the cost - effectiveness of CCS for these units would be much higher than for base load units. We have also concluded that the high
- efficiency NGCC units designed for base load applications do not meet any of the BSER criteria for non -base load units . First, non
-base load units need to be able to start and stop quickly, and NGCC units designed for base load applications require relatively long startup and shutdown periods. Therefore, conventional NGCC design s are not technically feasible for the non -base load subcategory . Also, non -base load units operate less than 10 percent of the time on average . As a result, conventional NGCC units designed for base load applications, which have relatively high capital costs , will not be cost - effective if operate d as
non -base load unit s . In addition, it is not clear that a conventional NGCC unit will lead to emission reductions if use for non -base load applications . As some commenters noted,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **536** of **763** conventional NGCC units have relatively high startup and shutdown emissions and poor part - load efficiency , so emissions may actually be higher compared with simple cycle technologies that have lower overall design efficiencies but better cycling efficiencies . Finally, requiring conventional NGCC units as the BSER for non -base load combustion turbines would not promote technology because these units would not be fulfilling their intended role. In fact, it could hamper the development of technologies with lower design efficiencies that are 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 that conventional NGCC units designed for base load applications are not the BSER for non -base load natural gas - fired units. Compared to conventional NGCC technology , fast - start NGCC units have lower de s ign efficiencies, but are able to start and ramp to full load more quickly. Therefore, i t is possible that requiring fast
- start NGCC as the BSER for non -base load units would result in emission reductions and further promote 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 NGCC , which have relatively high capital costs compared to simple cycle turbines,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **537** of **763** as the BSER for all non -base load applications. Also, as we explained above in s ection IX.B.2 , we do not have sufficient emissions data for fa s t - start NGCC units operating over the full range of non -base load conditions (e.g., peaking, cycling, etc.), so we would not be able to establish a reasonable emission standard. High
- efficiency simple cycle turbines are primarily used for peaking applications. High
- efficiency simple cycle turbines often employ aeroderivative designs because they are more efficient at a given size and are able to startup and ramp to full load more quickly than industrial frame designs . Requiring high
- efficiency simple cycle turbines as the BSER could result in some emission reductions compared with conventional simple cycle turbines. It would also promote technology development by incentivizing manufacturers to increase the efficiency of their simple cycle turbine models . However, aeroderivative designs have higher initial costs that must be weighed against the specific peak
- load profiles anticipated for a particular new
non -base load unit. Many utility companies have elected to install the heavier industrial f rame turbines because the ramping capabilities o f aeroderivative turbines are not required for their system demand profiles (i.e., the speed and durations of daily changes in electricity demand), and the fuel savings do not justify the higher initial costs. We currently do not have***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **538** of **763** precise enough costing information to compare the cost effectiveness of aeroderivative turbines and industrial frame turbines for all non
-base load applications . Determining cost effectiveness is further complicated because the efficiencies of the available aeroderivative and industrial frame technologies significantly overlap . For example, the efficiencies of aeroderivative turbines range from 32 to 39 percent, while the efficiencies of industrial frame turbines range from 30 to 36 percent. Based on the se cost uncertainties , we cannot conclude that high
- efficiency simple cycle turbines are the BSER for natural gas - fired non
-base load applications at this time . The final option that we considered for the BSER was clean fuels, specifically natural gas with a small allowance for distillate oil. The use of clean fuels is technically feasible for non -base load units. Based on available EIA data , 541 natural gas comprises more than 96 percent of total heat input for simple cycle combustion turbines. In addition, natural gas is frequently the lowest cost fossil fuel used in combustion 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 . Finally, the use of clean fuels will not have any significant energy or non
- air
541 http://www.e ia.gov/electricity/data/eia923/***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **539** of **763** impacts. Based on these factors, the EPA has determined that the BSER for non -base load natural gas - fired units is the use of clean fuels , specifically natural gas with a small allowance for distillate oil . Natural gas has approximately thirty percent lower CO 2 emissions per million Btu than other fossil fuels commonly used by utility sector non -base load units . c . Multi
- fuel - fired units . To identify the BSER for multi
- fuel - fired units , we again evaluated CCS, NGCC technology , high
- efficiency simple cycle units (i.e., aeroderivative turbines), and clean fuels. For each of these technologies we considered technical feasibility, costs , energy and non - air quality impacts, emission reduction s , and technology promotion. For many of the same reasons we provided above in our discussion of the BSER for non -base load natural gas - fired combustion turbines , only clean fuels meets the BSER criteria for multi
- fuel - fired units. While CCS would result in emission reductions and the promotion of technology, we concluded that CCS does not meet the BSER criteria because multi
- fuel - fired units tend to start, stop, and operate at part load frequently. Also, there are impurities and contaminants in some alternate fue ls which make the technical challenges of applying CCS to multi
- fuel - fired units greater than for natural gas - fired units .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **540** of **763** In regards to NGCC technology , we have concluded that it is technically feasible, would result in emission reductions, is cost - effective, and would promote the development of technology. However, a BSER determination based on the use of NGCC technology could pose challenges for fac ilities operating in remote locations and certain industrial facilities. I n remote locations , the construction of a NGCC facility is often not practical because it require s larger capital investments and significant staffing for construction and operation. In contrast, simple cycle turbines are cheaper and can be operated with minimal staffing. Also, many industrial facilities do not have the space available to build a HRSG and the associated cooling tower. Therefore, requiring NGCC as the BSER could have unforeseen energy impacts at these types of facilities. Moreover, these same kinds of facilities also burn by
-product fuels . Faced with a decision to install an NGCC unit, these facilities might seek alternative energy options, which could lead to increased flaring o r venting of by-product fuels because they are no longer being burned onsite for energy recovery. Therefore, in light of these potential energy and non - air quality impacts , we have concluded that NGCC technology is not the BSER for multi
- fuel - fired combustion turbines. Similarly, while high
- efficiency simply cycle turbines would result in emission reductions and promote the advancement***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **541** of **763** 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 not a s flexible with regards to what fuels that can be burned . Because by-product fuels vary in composition , it is not clear that all by-products fuels could be burned in a high
- efficiency simple cycle turbine . In addition, even if a by
-product fuel coul d be burned in an aeroder ivative turbine, we do not have information
on the potential for increased maintenance costs , we so cannot determine whether using high
- efficiency simple cycle turbines would be cost - effective . The final option that we considered for the BSER was clean fuels . The use of clean fuels is technically feasible and cost effective . The use of clean fuels also provides an environmentally beneficial alternative to the flaring or venting of by-product fuels and limit s the use of dirtier fuels with higher CO 2 emission rates , such as residual oils . Clean fuels also promote technology development by allowing manufacture r s to develop new combustion turbine designs that are capable of burning by
-product fuels that currently cannot be burned in combustion turbines. Finally, the use of clean fuels does not have any significant energy or non
- air quality impacts. Based on these factors, the EPA has determined that the BSER for multi
fuel - fired combustion turbines is the use of clean fuels.***EO 12866_Review
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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 the ir design efficiency and that burn more than 90 percent natural gas (i.e., base load natural gas - fired units) will be subject to an output
based standard. The output -based standard is based on the performance of existing NGCC units and takes into account a range of operating conditions, future degradation, etc . Units not meeting either the percentage electric sales or natural gas use criter ia (i.e., non -base load natural gas - fired and multi
fuel units , respectively) will be subject to an input
-based standard based on the use of clean fuels. This section summari z es what emission standards we proposed and related issues we solicited comment on, describes the comments we received regarding the proposed emission standards and our response s to those comments, and our rationale for the final emission standards . 1. Proposed Standards At proposal, we concluded that, for a combustion turb ine designed to sell more than one
- third of its potential el ectric output, using combined cycle technology (i.e., using a HRSG) is both cost effective (i.e., results in a lower cost of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **543** of **763** electricity) and results in a lower emission rate compared t o a simple cycle turbine . For new, modified, and reconstructed units we proposed a limit of 1,000 lb CO 2 /MWh - g for large units (base load rating greater than 850 MMBtu/h) and 1,100 lb CO 2 /MWh - g for small units (base load rating of 850 MMBtu/h or less). We solicited comment on a range of 950

– 1,100 lb CO 2 /MWh for large stationary combustion turbines and an emission standard range of 1,000

– 1,200 lb CO 2 /MWh for small stationary combustion turbines. We also solicited comment on eliminating the size subcategory, increasing the size distinction between large and small stationary combustion turbines to 900 MMBtu/h to account for larger aeroderivative designs , to 1,000 MMBtu/h to account for future incremental increases in base load ratings , or on increasing the size distinction to between 1,300 to 1,800 MMBtu/h
. To account for potential reduced efficiencies when not operated as a base load unit, we also solicited comment on whether a separate less stringent standard should be established fo r peaking and intermittent load combustion turbines . 2. Comments As described previously, we are finalizing emission standards for three subcategories of stationary combustion turbines. The relevant comments are discussed for natural gas
-***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **544** of **763** fired base load units and natural gas
- fired non
-base load units. Comments supporting tiered emission standards are included in the natural gas - fired non
-base load units. We did not receive comments on an appropriate emission standard for multi
- fuel units.
a . Emission standards for base load natural gas - fired units . Many commenters stated that the proposed emission standards do not properly consider the losses in efficiency that occur due to long- term degradation (e.g., multiple decades) , reductions in efficiency due to operation at non -base load conditions (load cycling, frequent startups and shutdowns, and part
- load operations), site
- specific factors (e.g., ambient conditions and cooling technology) , and secondary fuel use (e.g., distillate oil). Commenters stated that the EPA should conduct a more comprehensive BSER analysis that addresses worst
- case conditions for each of these factors . Commenters also stated that all of the units included in the analysis supporting the proposal are relatively new and have experienced limited degradation. Commenters stated that to the extent that some degradation can be recovered during periodic maintenance outages, it is not always possible or feasible to repair a degraded component immediately, as repairs often involve extended outages that must be scheduled well in advance. Commenters state d that a new unit that initially could meet the standard at base load conditions***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **545** of **763** can experience increasing heat rates with age even when adhering to the manufacturer's recommended maintenance program. Commenters stated that the proposed standards for combustion turbines were derived from years with historically low natural gas prices when NGCC units were run at historically high capacity factors so that the efficiencies and CO 2 emission rates underlying the proposed standards are not representative of future periods with higher natural gas prices. Other commenters said that many NGCC units are increasingly required to cycle and operate at lower capacities (compared to the proposal's baseline) t o accommodate hourly variations in intermittent renewable generation (e.g., solar and wind) . Such generation may be anticipated to increase, and thus future cycling EGUs may start and stop and operate at part load more frequently than in the past, increasi ng CO 2 emissions. Commenters indicated that, during startup, combustion turbines must be operated at low load for extended periods to gradually warm up the heat recovery steam generator (HRSG) to minimize thermal stresses on pressure vessels and boiler tubes. During these startup periods, significant CO 2 emissions occur but steam production is not sufficient for the steam turbine generator to produce electricity. Commenters also stated that a similar situation occurs during shutdown when the steam cycle does not generate electricity but the combustion turbine is***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **546** of **763** still combusting fuel as it proceeds through the shutdown process. Commenters recommended that the EPA could address these issues by creating a subcategory for cycling and intermediate load NGCC units . Many commenters said that site
- specific factors can often preclude operators from achieving design efficiencies based on ISO conditions . These factors include high elevations , high ambient temperatures , and cooling system constraints . Commenters stated that local water temperatures can impact condenser operating pressure and heat rates. Commenters also said that areas with limited water resources could require systems that rely on air
- cooled condensers and that cannot achieve thermal efficiencies comparable to water cooled plants. These c ommenters stated that the final rule should include provisions for addressing site
- specific constraints that preclude individual affected EGUs from achieving the emissions rates achieved on average by other sources. Commenters also stated that the proposed standards for modified and reconstructed combustion turbines foreclose future opportunities for operators to undertake projects to restore the performance of both degraded units subject to the NSPS and existing, pre
-NSPS units. Many commenters 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 units because***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **547** of **763** many newer technological options that deploy higher temperatures are not available to pre
- 2000 combustion turbines due t o their materials of construction. Commenters from the power sector generally supported increasing the standard for each subcategory to 1,100 lb CO 2 /MWh g for large units and 1,200 lb CO 2 /MWh - g for small units and finalizing standards for modified and rec onstructed standards that are 10 percent higher than the final standards for newly constructed combustion turbines because combustion turbines constructed prior to 2000 were not included in the EPA's BSER analysis for new sources . Conversely, some comment ers stated that the proposed standards for combustion turbines do not reflect the emission rates that are achievable by modern, efficient NGCC power blocks . Some commenters stated that the appropriate standard , consistent with Congressional objectives under CAA section 111, is 800 lb CO 2 /MWh - g based on the performance of the lowest emitters in the CAMD database. Some commenters stated that a standard of 850 lb CO 2 /MWh - g reflect s BSER for high
- capacity factor units because half of the combined cycle plants in the CAMD database are achieving this level of emissions. One commenter from the power sector who operates combined cycle power plants stated that the final standard for new l arge combustion turbines should be 925 lb CO 2 /MWh - g . One commenter***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **548** of **763** supported an emission standard consistent with recent BACT determinations in the State of New York of 925 lb CO 2 /MWh
- g. Several other commenters stated that a reasonable standard for
new combustion turbines would be 950 lb CO 2 /MWh - g , and several commenters stated that the final standard for new small combustion turbines should be 1 , 000 lb CO 2 /MWh - g . Numerous commenters stated that the final standard for new sources should not exceed 1,000 lb CO 2 /MWh - g for either large or small combustion turbines. Other commenters stated that since the standards were developed based on emission rates that are being achieved by the majority of existing units, the final standards should be the same for new, modified, and reconstructed units. b. Emission standards for non -base load natural gas - fired units and multi
- fuel - fired units . With respect to coverage of non -base load combustion turbines, commenters noted that the EPA cannot finalize “no emission standard” as the EPA solicited comment on in the broad applicability approach. Some commenters recommended that non base load units should be subject to work practice standards such as operating safely and with good air pollution control practices, including CO 2 monitoring and reporting requirements. Other commenters pointed to recent BACT limits for CO 2 that indicate tiered limits are appropriate for the different roles served by combustion turbines citing BACT limits from 1,328 to***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **549** of **763** 1,450 lb CO 2 /MWh
- g for peaking units. One commenter supported tiered limits consistent with recent BACT determinations in the State of New York a simple cycle limit of 1,450 lb CO 2 /MWh
- g. An air quality regulator from a state with rapidly increasing renewable generation supported a limit of 825 lb CO 2 /MWh
- g for base load NGCC units; 1,000 lb CO 2 /MWh
- g for intermediately loaded, large NGCC units; 1,100 lb CO 2 /MWh
- g for intermediately loaded, small NGCC units; and this commenter recommended that the EPA set a numerical limit specifically for peaking units after completion of a peaker
- specific BSER analysis. Several commenters supported tiered standards based on capacity factor. They proposed 825 lb CO 2 /MWh
- g for base load units (those operating over 4,000 hours annually), 875 lb CO 2 /MWh
- g for intermediate and load
- following units (those operating between 1,200 and 4,000 hours annua lly), and 1,100 lb CO 2 /MWh
- g for peaking units (those operating less than 1,200 hours per year). 3. Final Standards
a. Newly constructed base load natural gas - fired units . Since the standards were proposed, the EPA has expanded the NGCC emissions rate analysis that supported the proposed emission standards to include emissions information for NGCC units that commenced operation in 2011, 2012, and 2013 and updated the emissions data to include emissions through 2014. I n our analysis, we evaluated 346 NGCC units with online dates***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **550** of **763** ranging from 2000 to 2013. The analysis included emissions data from 2007 to 2014 as submitted to the EPA’s Clean Air Markets division (CAMD). The maximum 12
- operating month CO 2 emission rate is 897 lb CO2/MWh
- g with individual unit maximums ranging from 751 to 1,334 lb CO 2 /MWh
- g. Based on analysis of these data and the comments submitted on the proposed standard, the EPA has concluded that an emission standard of 1,000 lb CO 2 /MWh - g is achievable for natural gas fired base load NGCC units regardless of size . Therefore, the EPA is finalizing an emission standard of 1,000 lb CO 2 /MWh - g for all combustion turbines. In determining this, we reviewed the
emissions data for both small and large NGCC units. For small units, we evaluated emissions data from seventeen NGCC units with heat input ratings of 850 MMBtu/h or less . The se units had
an average 12
- operating month maximum CO 2 emission rate of 95 3 lb/MWh - g . Individual smal l unit 12
- operating month average emission rates ranged from 898 to 1,175 lb CO 2 /MWh
- g. Two of the units had a maximum 12
- operating month rolling average emissions rate equal to or greater than 1,000 lb CO 2 /MWh - g . 542 One of the units with maximum emission rates above 1,000 lb CO 2 /MWh was operating significantly below the design specific percentage electric sales threshold when the higher emissions rate
542 For emission standards of 1,000 lb CO2/MWh
- g and above the emission standard uses three significant figures.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **551** of **763** occurred. Therefore, the applicable emission standard would have been the heat input based clean fuels standard and the unit would not have been out of compliance with the final emission standard. Therefore, sixteen of the seventeen existing small NGCC units have demonstrated that an emission rate of 1,000 lb CO 2 /MWh
- g is achievable. In addition, the six newest units commenced construction between 2007 and 2012 . All of these units have maximum 12
-month emission rates of less than 950 lb CO 2 /MWh g . Even though these units might not have experienced their full degredation due to age, th is demonstrates that the final natural gas - fired base load emission standard includes a significant compliance margin that accounts for potential future degredation. For larger units, the average 12
- operating month maximum emission rate is 895 lb CO 2 /MWh
- g, with individual unit 12
- operating month maximum emission rates ranging from 751 to 1, 334 lb CO 2 /MWh
- g. Twenty three of the 3 28 large NGCC had maximum 12
- operating month emission rates greater than 1,000 lb CO 2 /MWh. However, while we do not have the design efficiency and cannot calculate the precise percentage electric sales threshold, it appears that all of the emission rates in excess of 1,000 lb CO 2 /MWh
- g occurred when electric sales were below the natural gas - fired base load percent electric sales criteria. These units would only have to comply with the heat input
-based clean fuels***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **552** of **763** standard when in the natural gas
- fired non
-base load subcategory. Therefore, essentially all existing NGCC units would have been in compliance with the final emission standards. Further, there were 51 new combustion turbine units that started operation since 2010, and the average emission rate from these units is 833 lb CO 2 /MWh
- g. Based on this, the EPA has concluded that the final emission standard includes significant compliance margin to account for potential future degredation. To evaluate degredation, the EPA reviewed the emission rate information for the 55 oldest NGCC units in our data set that came online in 2000 and 2001 . According to c ommenters, we expected to see degredation when reviewing the emissions data since it contained data from turbines between 7 to 14 years old. However, we did not see any sign if degredation. The CO 2 rates have little standard deviation for each unit between 2007 and 2014. In addition, there are many instances where the CO 2 emission rate decreases as a unit ages . This indicates that the efficiency of the unit is increasing and this could be due to good operating and maintenance procedures, as well as upgrading equipment to improve efficiency beyond the original design efficiency . Based on this we have concluded that our analysis adequately accounts for degredation. We also evaluated the impact of elevation , ambient temperature , cooling type, and operating conditions ( startups,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **553** of **763** shutdowns and average run time per start ), as commenters indicated that these could affect a unit's ability to achieve the standard. We saw little correlation between elevation and ambient temperature and emission rate. In addition, any correlation was relatively small and would have an insignificant impact on the ability to achieve the final standard. We identified 32 large NGCC units with dry cooling towers. The average maximum 12
- operating month emission rate for this group of units is 875 lb CO 2 /MWh. This is actually lower than for the large NGCC group as a whole. Based on this, we have concluded that the final emission standard does not limit the use of dry cooling technologies. While the natural gas
- fired non
-base load subcategory addresses operating conditions, the EPA evaluated
run time per start, average duty cycle, and number of starts on the emission rate and found that while these factors influence the emission rate, even the majority of natural gas - fired non base load NGCC could comply with the natural gas
- fired base load emission rate. For a detailed discussion of these issues, please see the technical support document. In addition to emis s ion rate information from existing NGCC demonstrating the final emission standard is achievable , multiple technologies that can increase the performance of new combined cycle facilities are currently available. First, vendors continue to improve the single cycle efficiency of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **554** of **763** combustion turbines. The use of more efficient combustion turbine engines improves the overall eff iciency of combined cycle facilities. In addition, existing smaller combined cycle facilities were likely designed using single or dual pressure heat recovery steam generators without a reheat cycle. New designs could incorporate three pressure steam generators with a reheat cycle to improve the overall efficiency of the combined cycle facility. Finally, additional technologies to reduce 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 emission rate approximately five percent less than an electric only NGCC. The EPA also reviewed the NGCC unit GHG limitations that have been included in construction permits since January 1, 2011 . The Permit TSD provides more detailed analysis and description of the plants and permits evaluated. All permit limits were evaluated over an annual period. In total 31 major permits were identified with 39 discrete limits on GHG emissions. Eight of the limits were expressed as lb /h or tons per year and were not included in the analysis. In addition, one CHP unit that generates electricity and s upplies steam to a chemical plant was in the set with a limit of 1,362 lb CO 2 /MWh based only on the gross electrical portion of output and does***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **555** of **763** not account for the useful thermal output. Therefore, it was also not included in this analysis. Two of the permits did not clearly specify if the output based standard was on a gross or
ne t basis and were therefore also excluded. The remaining 28 permit standards were expressed on a lb CO 2 /MWh or a heat rate basis that could be converted to 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 limits were based on gross output ranging from 833
- 1,100 lb CO 2 /MWh - g . Of these 28 permit limits, only one unit had a heat input capacity less than 1,500 MMBtu/h (366 MMBtu/h); this unit also had the highest emission limit of 1,100 lb CO 2 /MWh. Each of the permit limits discussed above that is 1,000 lb CO 2 /MWh or include all periods of operation (i.e., including startup, shutdown and malfunction ) . In addition, a ll permit limits were set considering the backup and additional fuel use. Specifically, some permits restricted fuel use to only natural gas , while others limited the available usage (duration and type) of backup and other fuels . For example, the Pioneer Valley Energy Center has unrestricted use of natural gas while restricting operation with ultra
- low sulfur diesel (ULSD) to 1,440 hours per 12
-month period. This permit allows up to 16***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **556** of **763** percent use of a fuel other than natural gas and the facility accepted a permit limit of 895 lb CO 2 /MWh
- net. E ach permit limit also considered the mode of operation for the combustion turbine. In some cases the permit limit was determined to be appropriate because the combustion turbine is intended to
operate with frequently changing loads rather than operating at relatively steady loads, and this mode of operation would make it difficult to meet lower limits. In the instances for most of the units with the lower emission limits, their permits specified that the combustion turbines will be operating at base load, so they will be able to operate closer to their most efficient load levels. For example, the Lower Colorado River Authority's Ferguson plant evaluated emission limits for the plant at 50, 75 and 100 percent gross load, since the expected operation is 50 percent gross load, the plant accepted an emission limit of 918 lb CO 2 /MWh
- n for the corresponding evaluation . For the combined cycle combustion turbine units with duct burners on their HRSG, the hours of operation with duct burners was included in the determination of the permit limits. Typically, the hours of operation and heat input we re limited to ensure that the units are operated in the most efficient way and reduce their CO 2 emissions. Finally, most of f these permits included an allowance for efficiency losses due to degradation***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **557** of **763** The sum of these allowances was in the range of 10 to 13 percent reduction in the design efficiency . In addition to the combined cycle operating data and permit review, we also reviewed combined cycle design efficiency data and specifications submitted to Gas Turbine World (GTW). Specifically, we review the reported efficiency data for 90 60 Hz combined cycle units form Alstom, GE Energy Aeroderivative and Heavy Duty, Mitsubishi Heavy Industries, Pratt & Whitney, Rolls -Royce, and Siemens Energy. The reported design s ranged in model year from 1977 to 2011, capacities ranged from 24 to 1,026 MW, and base load ratings ranged from 190 to 3,551 MMBtu/h . The average reported design emission rate for these units is 836 lb CO 2 /MWh
- n and ranged from 725 to 968 lb CO 2 /MWh
- n . The corresponding compliance margin relative to the standard of 1,030 lb CO 2 /MWh - n averaged 24 percent and ranged from 5 to 42 percent. For the 54 small units (base load rating of 850 MMBtu/h or less ), average design efficiency was 51.2 percent and the values ranged from 45.0 to 55.6 percent with the calculated compliance margin average at 19 percent and a range from 5 to 29 percent. The unit least efficient in this analysis was a 24 MW with a heat input of 190 MMBtu per hour, so it would not be subject to this rule unless it included sufficiently sized duct burners for supplementa l firing to meet the applicability criteria , although it would still meet the standard. The 2 next***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **558** of **763** smallest units would not be subject to this rule either, as they were less than 250 MMBtu per hour base load heat input, and they also met the standard. For larger units ( base load rating greater than 850 MMBtu /h ), the average design efficiency was 56.6 percent and ranged from 50.1 to 61.7 percent. The calculated compliance margin average was 31 percent and ranged from 16 to 42 percent. Even the base model from a single manufacturer has many options for the purchased combustion turbine to provide the necessary efficiency and operating ranges. Choosing a NGCC unit with dual pressure or triple pressure instead of single pressure will improve the efficiency of a unit. The combustion options, such as dry low emission (DLE) burners or water injection to reduce NOx output. For example, GE Energy Aeroderivative offers multiple models and years of design for their LM2500 model
- type. The 1981 LM2500PE model has a heat input of 259 MMBtu/h and an efficiency of 50.4 percent and compliance margin of 17 percent. The LM2500+PK 1995 model has an input of 319 MMBtu / h, efficiency of 47.5 percent, and compliance margin of 10 percent. The 2005 LM2500+G4RD has a heat input of 32 3 MMBtu/h , efficiency of 53.6 percent, and compliance margin of 24 percent. b. Reconstructed base load natural gas - fired units . We disagree with commenters that stated that reconstructed combustion turbines would not be able to achieve the final***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **559** of **763** emission standards. For the reasons listed below, we have concluded that for an existing NGCC that is reconstructed an emission rate of 1,000 lb CO 2 /MWh
- g is achievable, regardless of size. In addition, an owner or operator considering reconstructing an existing simple cycle turbine would decide how they wish to run that combustion turbine in the future. Similar to a newly constructed combustion turbine, i f they anticipate running above the percentage electric sales threshold, then the BSER would be the use of combined cycle technology. If they intend to run as a non
-base load units, the BSER would be the use of clean fuels. Highly efficient NGCC units include (1) an efficient combustion turbine engine, (2) an efficient steam cycle, and (3) a combustion turbine exhaust system that is “matched” to the steam cycle for maximum efficiency. In order for an existing NGCC unit to tri gger the reconstruction provisions, the unit would have to essentially be entirely rebuilt. This involves upgrades to both the combustion turbine engine and HRSG. Therefore, a reconstructed NGCC unit is would be able to maximize the efficiency of the turbine engine, the steam cycle, and match the two for maximum efficiency. According to comments submitted as part of the existing source 111(d) proposal there are various options available to improve the efficiency of existing combustion turbines. One***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **560** of **763** combustion turbine manufacturer provided comments describing technology upgrades available to improve the efficiencies of existing combustion turbines, specifically, the compressor, combustor , and gas turbine components. This manufacturer stated that operators of existing turbines can replace older internal components along the gas path with state
- of - the - art components that have higher aerodynamic efficiencies and improved seal designs. These gas path enhancements 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 manufacturer stated that utilities deploying these gas path improvements on reconstructed frame type combustion turbines with nominal output ratings of 170 to 180 MW can increase their output by 10 MW while reducing CO 2 emissions by more than 2.6 percent compared to baseline unit . In addition to gas path and software improvements, the manufacturer stated that the newest low-NOx combustor designs can be retrofitted on modified and reconstructed turbines to achieve lower NOX emissions, to improve turndown (i.e., to enable stable operations at lower loads compared to the lowest stable load achievable at baseline conditions), and to improve efficiencies across all load conditions. The manufacturer indicated that operators of existing combustion turbines deploying both state
-***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **561** of **763** of - the - art gas path, software, and combustor upgrades can increase output on frame
- style turbines by 14 MW (on units with nominal output ratings between 170 and 180 MW) while reducing CO 2 emissions by 2.8 percent. In addition to the preceding upgrades, the manufacturer stated that existing combustion turbines can achieve the largest efficiency improvements by upgrading existing compressors with more advanced compressor technologies, potent ially improving the combustion turbine's efficiency by an additional 3.8 percent improvement (i.e., the total potential CO 2 emissions rate reduction for the combustion turbine only considering all upgrades offered by the manufacturer is up to 6.6 percent.) In addition to upgrades to the combustion turbine engine, a reconstructed NGCC unit also have the opportunity to improve the efficiency of the HRSG and steam cycle. Specific to the steam turbine, a steam turbine manufacturer identif ied three retrofit technologies available for reducing the CO 2 emissions rate of existing steam turbines by 1.5 to 3 percent: (1) steam path upgrades can minimize aerodynamic and steam leakage losses; (2) replacement of the existing hi gh pressure turbine stages with state - of - the - art stages capable of extracting more energy from the same steam supply; and (3) replacement of low
-pressure turbine stages with larger diameter components that extract additional energy and that reduce velociti es, wear, and***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **562** of **763** corrosion. In addition, a reconstructed NGCC could upgrade the entire steam cycle. For example, combined cycle units originally constru cted with only a single pressure level can be upgraded to also include second and third pressure levels. Studies 543 , 544 , 545 , 546 show that converting a single pressure HRSG with steam reheat to a double pressure configuration with steam reheat can reduce the CO 2 emission rate of an NGCC by 1.5 to 1.7 percent, and conversion from a single pressure configuration with reheat to a triple pressure configuration with reheat can yield a 1.8 to 2 reduction in the CO 2 emission rate . Similarly, units constructed with only a double pressure configuration without reheat can obtain a 0 .4 CO 2 emission rate reduction by adding a reheat cycle or a 0.9 CO 2 emission rate reduction by converting to a triple pressure configuration and adding a reheat cycle. Existing combined cycle combustion turbines that convert to these

543 "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. 544 "Combined Cycle Power Plant Performance Analyses Based on Single
- Pressure and Multipressure Heat Recovery Steam Generator." M. Raham, Journal of Energy Engineering, 138:136
- 145, 2012. 545 "Thermodynamic Evaluation of Combined Cycle Plants. " N. Woudstras et al. Energy Conversion and Management 51:1099
- 1110, 2010. 546 "A Comparative Evaluation of Advanced Cycle Alternatives" (90
- GT - 335), O. Bollard, American Society of Mechanical Engineers, Gas Turbine and Aerospace Congress and Exposition, Brussels, Belgium, June 11
- 14, 1990.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **563** of **763** advanced HRSG configurations and that deploy the previously discussed combustion turbine and steam turbine upgrades can realize CO 2 emission rate reductions ranging from 6 to 10 percent, depending on their baseline design and condition . Based on the available options to improve efficiency of existing NGCC units and that the vast majority of existing NGCC units are already achieving 1,000 lb CO 2 /MWh
- g, we have concluded that reconstru cted NGCC units could achieve this emission rate . c . Newly constructed and reconstructed non -base load natural gas - fired units . We are finalizing an input based standard based on the use of clean fuel, 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 operati on 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 output based standard for non -base load natural gas fired combustion turbines. The clean fuel based input bas ed standard require s these units to burn fuels with an average emission rate of 120 lb CO 2 /MMBtu or less . This standard is readily achievable since the CO 2 emission rate of natural gas is 11 7 lb CO 2 /MMBtu. The most common backup fuel is distillate oil and it has a CO 2 emission rate of 163 lb CO 2 /MMBtu. A non
-base load natural gas - fired combustion turbine burning 9 percent***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **564** of **763** distillate oil and 91 percent natural gas has an emission rate of 121 lb CO 2 /MMBtu , which rounds to 120 lb CO 2 /MMBtu using 2 significant digits. Therefore, the vast majority of owners and operators of natural gas - fired non
-base load combustion turbines will be able to achieve the standard using business as usual fuels. While the reductions that result from restricting the use of fuels with higher CO 2 emission rates is minor , the compliance burden is also minimal. Owners and operators of natural gas fired non
-base load stationary combustion turbines burning fuels with consistent chemical compositions that mee t the clean fuels
re quirement (e.g ., natural gas, ethylene, propane, naphtha, jet fuel kerosene, distillate oils 1 and 2, and biodiesel) would only need to maintain records that they only 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 composition that varies (e.g., residual oil, non jet fuel type kerosene, landfill gas) would have to follow the procedures in part 98 of this 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 would have to submit quarterly reports to verify that they are in compliance with required emission standard.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **565** of **763** d . Newly constructed and reconstructed multi
- fuel - fired units . In considering the BSER analysis for multi
- fuel - fired units, we also considered what CO 2 emissions data we currently have, the potential efficiency impacts of different fuels, and the relative carbon content of those fuels. The continuous emissions rate information we currently have is data that has been submitted to the EPA’s Clean Air Marke ts Division. Only turbines located in the lower 48 states report to this program, and they almost exclusively burn natural gas. Therefore, we do not have actual emissions rate data for other than natural gas
fired combustion turbines. Without these data we cannot establish a standard independent of the data for natural gas
fired combustion turbines. In addition, without these data we cannot determine the impact on efficiency of burning different fuels in combustion turbines. The chemical compositions of by
product fuels can vary significantly, which would directly affect the heating value of the fuel and the efficiency of the combustion unit. In addition, a combustion turbine that is designed or maintained to burn multiple fuels will inherently have an optimum efficiency that is below that of a combustion turbine burning a single fuel. Based on the lack of these data, we have concluded that we cannot establish an output based emission standard for multi
- fuel combustion turbines at this time.***EO 12866_Review
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We are finalizing input
-based standards, as opposed to an output -based standard, for new and reconstructed multi
- fuel fired combustion turbines burning 90 percent or less natural gas. The EPA has concluded that , at this time , we do not have sufficient info rmation to set a meaningful output
-based standard for these sources . As discussed earlier, we identified clean fuels , including natural gas , distillate oil , and other commonly used fuels , to be the BSER for this subcategory . The use of clean fuels will ens ure that new 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 we have concluded that it is necessary to use an equation based on the heat input from natural gas to determine the applicable 12
- operaint month emission standard. We have determined that the emission standard that can be achieved by multi
- fuel - fired combustion turbines burning clean fuels will vary from 120 lb CO 2 /MMBtu to 160 lb CO 2 /MMBtu on a 12
- operating month rolling average depending on the particular fuel mixture . For example, a combustion turbine that fired 85 percent natural gas (with a carbon content equivalent to 11 8 lb CO 2 /MMBtu) and that also fired 15 percent fuel oil (with a carbon content equivalent to***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **567** of **763** 162 lb CO 2 /MMBtu) would be subject to a heat - input
-weighted emission limit . According to the final data published by both CAMD and the EIA for 2013, natural gas was used to generate more than 98 percent of all the electricity delivered to the grid by combustion turbines with nameplate capacities greater than 25 MW. These data show that the primary, non
- natural gas fuels used by combustion turbines for the production of electricity are fuel gas, residual fuel oil, distillate fuel oil, kerosene, and jet fuel. As shown in Table 18 the carbon contents of these
non - natural gas fuels range from 118 to 180 lb CO 2 /MMBtu on a HHV basis . The final emission standard is based on a weighted average emission limit for periods when natural gas is fired with other fuels in order to limit the usage of high carbon fuels such as high
- carbon residual fuel oils. However, the final emission standard allows continued use of dist illate, jet fuel, fuel gas, propane, and liquefied petroleum gas. Combustion turbines in this subcategory are required to perform periodic fuel sampling when firing residual fuel oils and non - uniform fuels such as refinery fuel gas. Operators firing gases that already contain CO 2 (prior to combustion) may elect to utilize periodic sampling to determine the quantity of CO 2 in the stream prior to combustion and may exclude this portion from the compliance calculation. You must operate and***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **568** of **763** calibrate all flow meters, composition analyzers and pressure gauges used for measuring compliance parameters according to the procedures in §98.3(i). **Table 18**  **: Non -** **natural Gas Fuel Use for Electricity Generation 547**  **Fuel Average Carbon Content** **548 Fraction of National**  **Net Ge neration**  Other Gas 549 (fuel gas, propane, liquefied petroleum gas) 550 115 to 139 lb CO 2 /MMBtu 0.49 percent

Coal - derived synthesis gas Not applicable; units are subject to IGCC standard. 0.19 percent
Residual Fuel Oil (Nos. 5 and 6 and bunker C) 161 to 177 lb CO 2 /MMBtu 0.14 percent
Pet. Coke - derived synthesis gas Not applicable; units are subject to IGCC standard. 0.14 percent
Distillate fuel oils (Nos. 1, 2, and 4) 161 to 166 lb CO 2 /MMBtu 0.09 percent Kerosene and jet fuel 159 to 166 lb CO 2 /MMBtu 0.05 percent

547 Usage is based on EIA 923 data for RY201 3. 548 Average carbon contents taken from Table C - 1 of 40 CFR Part 98 and http://www.wiley.com/legacy/wileychi/morvayindustrial/supp/toolb ox5.pdf 549 The petroleum refining and chemicals sectors reported 0.28 of the 0.49 percent shown; the balance was reported by the utilities sector. 550 EIA does not publish specific fuels within the "Other Gas" fuel code, however EIA does publish the NAICS codes for facilities reporting this fuel code. The specific fuels listed are the gaseous fuels reported to 40 CFR Part 98 from the NAICS codes that also reported electricity generation to EIA associated with the "Other Gas" fuel code.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **569** of **763** Other biomass gases and liquids 115 to 180 lb CO 2 /MMBtu 0.01 percent

e. Modified units . The EPA is not finalizing the proposed emission standards for stationary combustion turbines that conduct modifications. As noted in section XV below , we are withdrawing the June 2014 proposal with respect to these sources. We received a significant number of comments asserting that modified combustion turbines could not meet the proposed emission standards of 1, 000 lb/MWh
- g for large turbines and 1,100 lb/MWh
g for small turbines . For the reasons explained in Section IX.B .1 above , we have decided not to subcategorize combustion turbines based on size for a number of reasons and are setting a single standard of 1,000 lb/MWh
- g for all base load natural gas fired turbines instead. While we are confident that all new and
rec onstructed units will be able to achieve this standard, we are less confident that smaller combustion turbines that undertake a modification will be able to do so. Until we have the opportunity to further investigate the full range of modifications that tu rbine owners and operators might undertake,
we consider it premature to finalize emission standards for these sources. Combustion turbines have unique characteristics that make determining an appropriate emission standard for modifi ed***EO 12866_Review
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sources a more challenging task than for coal - fired boilers. For example, each combustion turbine engine has a specific corresponding combustor . The development of more efficient combustor upgrades for existing turbine designs typically require s manufacturers to expend considerable resources. Consequently, not all manufacturers offer combustor upgrades for smaller or older designs because it would be difficult to recoup their investment. In contrast, efficiency upgrades for boilers can generally be installed regardless of the specific 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 backup fuel, such as distillate oil, to an existing turbine would likely trigger an NSPS modification. This is a relatively low
- capital
cost upgrade that would significantly increase a unit’s potential hourly emission rate , even though the annual emissions increase would be relatively minor because operating permit s generally limit the amount of distillate oil that a unit can burn . We need to conduct additional analysis to determine an appropriate emission standard for units that undertake this type of modification , which does not involve any of the combustion turbine components that impact efficiency. To be clear, the EPA is not reaching a final decision that***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **571** of **763** modifications should be subject to different requirements than we are finalizing in this rule for new and reconstru cted sources. We have made no decisions , and this matter is not concluded. We plan to continue to gather information, consider the options for modifications, and develop a new proposal 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 for those sources at this time. See section XV below . **X. Summary of Other Final Requirements for Newly Constructed, Modified, and Reconstructed Fossil Fuel**  **- fired**  **Electric Utility Steam Generating Units and Stationary Combustion Turbines**  This section describes the final action’s requirements regarding startup, shutdown, and malfunction; continuous monitoring; emissions performance testing; continuous compliance; and notification, recordkeeping, and reporting for newly constructed, modified , and reconstructed affected steam generating units and combustion turbines. We also explain 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) during periods***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **572** of **763** of startup, shutdown, and malfunction (SSM). Specifical ly, 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 302(k) of the CAA, emissions standards or limitations must be continuous in nature and that the SSM exemption violates the CAA's requirement that some CAA section 112 standards apply continuously. Consistent with Sierra Club v. EPA, the EPA has established standards in this rule that apply at all times. In establishing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained below as well as in section V.J.1 above , has not established alternate standards for those periods. Specifically, startup and shutdown periods are included in the compliance calculation as periods of partial load. The final method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the electric energy 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, during 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 t o be small***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **573** of **763** relative to the duration of periods of normal operation and that the fraction of power generated during periods of startup or shutdown is expected to be very small, the impact of these periods on the total average over a 12
- operating
-month period is expected to be minimal. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations. Malfunctions, in contrast, are neither predictable nor routine. Instead they are, by definition sudden, infre quent and not reasonably preventable failures of emissions control, process or monitoring equipment. (40 CFR 60.2). The EPA interprets CAA section 111 as not requiring emissions that occur during periods of malfunction to be factored into development of se ction 111 standards. Nothing in CAA section 111 or in case law requires that the EPA consider malfunctions when determining what standards of performance reflect the degree of emission limitation achievable through “the application of the best system of emission reduction” that the EPA determines is adequately demonstrated. While the EPA accounts for variability in setting emissions standards, nothing in CAA section 111 requires the agency to consider malfunctions as part of that analysis. A malfunction should not be treated in the same manner as the type of variation in performance that occurs during routine operations of a source. A malfunction is a failure of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **574** of **763** 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 emission standards would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all
s ources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” fores eeable. See, e.g., Sierra Club v. EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) (“The EPA typically has wide latitude 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, rather 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 si tuations. After a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case
-by- case enforcement discretion,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **575** of **763** not for specification in advance by regulation.”). In addition, emissions during a malfunction event can be significantly higher than emissions at any other time of source operation. 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 catch fire) and the emission unit is a steady state type unit that would take days to shut down, the s ource would go from 99 percent control to zero control until the control device was repaired. The source’s emissions during the malfunction would be 100 times higher than during normal operations. As such, the emissions over a 4 - day malfunction period woul d exceed the annual emissions of the source during normal operations. As this example illustrates, accounting for malfunctions could lead to standards that are not reflective of (and significantly less stringent than) levels that are achieved by a well
-per forming,
non -malfunctioning source. It is reasonable to interpret CAA section 111 to avoid such a result. The EPA’s approach 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 average over a 12
- operating
-month period is expected to be minimal. Thus,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **576** of **763** malfunctions over that period are not likely to result 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 result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the go od faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failu re to comply with the CAA section 111 standard was, in fact, sudden, infrequent, not reasonably preventable and was not instead caused in part by poor maintenance or careless operation. 40 CFR 60.2 (definition of malfunction). If the EPA determines in a pa rticular case that an enforcement action against a source for violation of 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 appropr iate. The same is true for citizen enforcement actions. Similarly, the presiding officer in an administrative proceeding can consider any defense raised and determine whether administrative penalties are appropriate.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **577** of **7 63**  In summary, the EPA interpretation of the CAA and, in particular, CAA section 111 is reasonable and encourages practices that will avoid malfunctions. Administrative and judicial procedures for addressing exceedances of the standards fully recognize that violations may occur despite good faith efforts to comply and can accommodate those situations. In the January 2014 proposal for newly constructed EGUs, the EPA had proposed to include an affirmative defense to civil penalties for violations caused by malfunctions in an effort to create a system that incorporates some flexibility, recognizing that there is a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances entirely beyond the control of the source. Although the EPA recognized that its
case -by- case enforcement discretion provides sufficient flexibility in these circumstances, it included the affirmative defense to provide a more formalize d approach and more regulatory clarity. See Weyerhaeuser Co. v. Costle , 590 F.2d 1011, 1057
- 58 (D.C. Cir. 1978) (holding that an informal case
by- 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 consideration of “upsets beyond the control of the permit holder”). Under the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **578** of **763** EPA’s regulatory affirmative defense provisions, if a source could demonstrate in a judicial or administrative proceeding that it had met the requirements of the affirmative defense in the regulation, civil penalties would not be assessed. Recently, the U.S. Court of Appeals for the District of Columbia 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 section 112 rule establishing emission standards for Portland cement kilns). The court found that the EPA lacked authority to establish an affirmative defense for private civil suits and held that under the CAA, the authority to determine civil penalty amounts in such cases lies exclusively with the courts, not the EPA. Specifically, the Court found: “As the language of the statute makes clear, the courts determine, on a case
-by- case 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 job for the courts, not EPA.”). 551 In light of NRDC, the EPA is not including a regulatory affirmative defense provision in this final rule.

551 The court’s reasoning in NRDC focuses on civil judicial actions. The court noted that “EPA's ability to determine 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
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– Do Not Cite, Quote or Release During Review *** Page **579** of **763** As explained above, if a source is unable to comply with emissions standards as a result of a malfunction, the EPA may use its case
-by- case enforcement discretion to provide flexibility, as app ropriate. Further, as the D.C. Circuit recognized, in an EPA or citizen enforcement action, the court has the discretion to consider any defense raised and determine whether penalties are appropriate. Cf. NRDC, at 1064 (arguments that violations were cause d by unavoidable technology failure can be made to the courts in future civil cases when the issue arises). The same is true for the presiding officer in EPA administrative enforcement actions. 552 B. Continuous Monitoring Requirements The majority of comment s received on the proposal supported the EPA ' s use of existing monitoring requirements under the Acid Rain Program , which are contained in 40 CFR part 75 requirements . In response to this , the EPA is finalizing monitoring requirements that incorporate and reference the part 75 monitoring requirements for the majority of the CO 2 and energy
552 Although the NRDC case does not address the EPA’s authority to establish an affirmative defense to penalties that is availabl e in administrative enforcement actions, the 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 caused by malfunctions in administrative proceedings and judicial proceedings should be consistent. Cf . CAA section 113(e) (requiring both the Administrator and the court to take specified criteria into account when assessing penalties).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **580** of **763** output monitoring requirements while ensuring accuracy and stringency required under the program. This final rule requires owners or operators of EGUs that combust solid fossil fuel to install, certify, maintain, and operate continuous emission monitoring systems (CEMS) to measure CO 2 concentration, stack gas flow rate, and (if needed) stack gas moisture content in accordance with 40 CFR part 75, in order to determine hourly CO 2 mass emissions rates (tons/hr). The rule allows owners or operators of affected EGUs that burn exclusively gaseous or liquid fuels to install fuel flow meters as an alternative to CEMS and to calculate the hourly CO 2 mass emissions rates using Equation G
- 4 in Appendix G of Part 75. To implement this option, hourly measurements of fuel flow rate and periodic determinations of the gross calorific 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”, expressed in megawatt hours (MWh). The gross output includes electrical output plus any mechanical output, plus 75 percent of any useful thermal output. The rule requires EGU owners or operators to prepare and submit a monitoring plan that includes both electronic and hard***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **581** of **763** copy components, in accordance with sections 75.53(g) and (h). The el ectronic portion of the monitoring plan should be submitted to the EPA’s Clean Air Markets Division (CAMD) using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion of the plan should be sent to the applicable State and EPA Regional office. Further, all monitoring systems used to determine the CO 2 mass emission rates have to be certified according to section 75.20 and section 6 of Part 75, Appendix A within the 180
- day window of time allotted under section 75.4(b), and are required to meet the applicable
on - going quality assurance procedures in Appendices B and D of Part 75. The rule requires all valid data collected and recorded by the monitoring systems (including data recorded during startup, shutdown, and malfun ction) to be used in assessing compliance. Failure to collect and record required data is a violation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of stack emissions (e.g., calibration error tests, linearity checks, and required zero and span adjustments). The rule requires only those operating hours in which valid data are collected and recorded for all of the parameters in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **582** of **763** CO 2 mass emission rate equation to be used for calculating compliance with applicable emission limits . Additionally for EGUs using CO 2 CEMS, only unadjusted stack gas flow rate values should be used in the emissions calculations. In this rule, Part 75 bias adjustment factors (BAFs) should not be applied to the flow rate data. These restrictions on the use of Part 75 data for Part 60 compl iance are consistent with previous NSPS regulations and revisions. Additionally if an affected EGU combusts natural gas and/or fuel oil and the CO 2 mass emissions rate are measured using Equation G
- 4 in Appendix G of Part 75, then determination of site
- spe cific carbon
-based F - factors using Equation F
- 7b in section 3.3.6 of Appendix F of Part 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 fi nal rule includes the following special compliance provisions for units with common stack or multiple stack configurations; these provisions are consistent with section 60.13(g):

 If two or more EGUs share a common exhaust stack, are subject to the same emi ssion limit, and the operator is required to (or elects to) determine compliance using CEMS, then monitoring the hourly CO 2 mass emission rate at the common stack instead of monitoring each EGU separately***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **583** of **763** is allowed. If this option is chosen, the hourly gross electrical load (or steam load) is the sum of the hourly loads for the individual EGUs and the operating time is expressed as “stack operating hours” (as defined in 40 CFR 72.2). Then, if compliance with the applicable emission limit is attained at the common stack, each EGU sharing the stack will be in compliance with the CO 2 emissions limit.

 If the operator is required to (or elects to) determine compliance using CEMS and the effluent from the EGU discharges to the atmosphere through multiple stacks ( 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 and recorded for all of the parameters used to calculate CO 2 mass emissions.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **584** of **763** EGU owners or operators have the option to use backup monitoring systems, as provided in sections 75.10(e) and 75.20(d), to help meet this data capture requirement. This requirement is separate from the requirement for a source to demonstrate compliance 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 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 for the proposal, commenters in general supported the use of current testing requirements required under the Acid Rain Program 40 CFR part 75 requirements. Thus the EPA is finalizi ng requirements for performance testing as consistent with part 75 requirements where appropriate to ensure the quality and accuracy of data and measurements as required by the final rule. In accordance with section 75.64(a), the final rule requires an EGU owner or operator to begin reporting emissions data when monitoring system certification is completed or when the 180
- day window in section 75.4(b) allotted for initial certification of the monitoring systems expires (whichever date is earlier). For EGUs subject to the 1,400 lb CO 2 /MWh - g ) emission standard, the initial performance test consists of the first 12***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **585** of **763** operating months of data, starting with the month in which emissions are first required to be reported. The initial 12
- operating
-month compliance pe riod begins with the first month of the first calendar year of EGU operation in which the facility exceeds the capacity factor applicability threshold. The traditional 3
- run performance tests (i.e., stack tests) described in section 60.8 are not required for this rule. Following the initial compliance determination, the emission standard is met on a 12
- operating
-month rolling average basis. D. Continuous Compliance Requirements Commenters supported the use of a 12
- operating month rolling average for the compliance period for the final standards. In response, this final rule specifies that 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
- operating
month compliance period, quality
- assured data from the certified Part 75 monitoring systems is used together with the gross output over that period of time to calculate the average CO 2 mass emissions rate. The rule specifies that the first operating month included in the initial 12
- operating
-month compliance period is the month in which reporting of emissions data is re quired to begin under section 75.64(a), i.e., either the month in which monitoring***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **586** of **763** system certification is completed or the month in which the 180
- day window allotted to finish certification testing expires (whichever month is earlier). Initial compliance with the applicable emissions limit in kg/MWh is calculated by dividing the sum of the hourly CO 2 mass emissions values by the total gross output for the 12
- operating
month period. Affected EGUs continue to be subject to the standards and maintenance requ irements in the CAA section 111 regulatory general provisions contained in 40 CFR part 60, subpart A. Several commenters stated that the final rule should require operators to round their calculated emissions rates to three significant figures when compari ng their actual rates to the standard. These commenters said that allowing use of only two significant digits when calculating the 12
- operating month rolling average emission rate would constitute relaxation of the standard by 5 percent because an actual emission rate of 1,049.9 lb CO 2 /MWh rounds to 1,000 lb of CO 2 per MWh when only 2 significant figures are required in the final step of compliance calculations. Commenters also suggested that the emission 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 should be used when evaluating compliance. Other commenters suggested that the final step in compliance calculations should reflect rounding***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **587** of **763** the emission rate to the neares t whole number using the ASTM rounding convention (ASTM E29). The General Provisions of Part 60 specify the rounding conventions for compliance calculations at 40 CFR 60.13(h)(3) including the provision that "after conversion into units of the standard, the data may be rounded to the same number of significant digits used in the applicable subpart to specify the emission limit." The final rule requires that the 12
- operating month rolling average emission rate must be rounded to 3 significant figures if the applicable emissions standard is greater than or equal to 1,000 (e.g., an actual emission rate of 1,004.9 lb CO 2 /MWh is rounded to 1,000 lb CO 2 /MWh); for standards of 1000 or less, the final rule requires rounding the actual emission rate to 2 sign ificant 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 Part 60 have been expressed to 2 significant digits (e.g., the original SO 2 emission standard for coal - fired units under Subpart D was 1.2 lb SO 2 /MMBtu). The rounding conventions under the General Provisions allow the reporting of all emission rates in the range from 1.15 to 1.249 as 1.2 lb SO 2 /MMBtu. During compliance peri ods with emissions at the lower end of this range, the operator is required to report higher emissions than actually occurred; during compliance***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **588** of **763** periods at the upper end of this range the operator is allowed to report lower emissions than actually occurred . In either case the absolute error remains small because the emission rate in this example is a relatively small numerical value. In addition, the required emission reductions typically are large enough that rounding does not impact the emission control s trategy of affected units. However, the final standards for CO 2 emissions include numerical values that are larger than many historical emissions standards and require a relatively small percent reduction in emissions. Accordingly, it is appropriate to require the use of three significant digits when completing compliance calculations resulting in numerical values larger than 1,000. This is particularly important when considering the relatively small emission rate changes that may be required for compliance with the unit
- specific emission standards being finalized for modified steam generating and IGCC units because a rounding error of 5 percent may be larger than the percent difference between the affected unit's historically best emission rate and the emis sion rate immediately preceding the modification. The final rule requires rounding of emission rates with numerical values greater than or equal to 1,000 to three significant figures and rounding of rates with numerical values less than 1,000 to two signif icant figures.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **589** of **763** E. Notification, Recordkeeping, and Reporting Requirements Commenters supported the coordination of notification, recordkeeping, and reporting required under this rule in conjunction with the requirements already in place under Part 75 and so the EPA has made the requirements as efficient and streamlined as possib le with the current requirements under Part 75. This final rule requires an EGU owner or operator to comply with the applicable notification requirements in section 75.61, sections 60.7(a)(1) and (a)(3), and section 60.19. The rule also requires the applic able 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 moisture content (if needed), unit operating time, and gross electric generation. For EGUs that exclusively combust liquid and/or gaseous fuel(s) and elect to determine CO 2 emissions using Equation G
- 4 in Appendix G of Part 75, the key data elements in subpart F that are recorded include hourly fuel flow rates, fuel usage times, fuel GCV, gross electric generation. The rule requires EGU owners or operators to keep records of the calculations they perform to determine the total 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **590** of **763** emission rates in each compliance period are required to be kept. The rule also requires sources to keep records of calculations performed to determine site
- specific carbon
-based F- factors for use in Equation G
- 4 of Part 75, Appendix G (if applicable). Sources are required to keep all records for a period of 3 years. All required records must be kept on
- site for a minimum of 2 years, after which the records can be maintained off
- site. The rule requires all affected EGU owners/operators to submit quarterly electronic emissions reports in accordance with subpart G of Part 75. The reports in Appendix G that 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 section 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., oil
- fired units), this is not a new reporting requirement. Sources subject to the Acid Rain Program are already required to report the hourly CO 2 mass emission rates that are needed to assess compliance with this rule. Additionally, in the final rule and as part of an agency
wide effort to streamline and facilitate the reporting of environmental data, the rule requires selected data elements that pertain to compliance under this rule, and that serve the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **591** of **763** purpose of identifying violations of an emission standard, to be reported periodically using ECMPS. Specifically, EGU owners/operators must submit quarterly electronic reports within 30 days after the end of each quarter consistent with current Part 75 reporting requirements. The first report is for the quarter that includes the final (12 th ) operating month of the initial 12
- operating
-month compliance 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 average CO 2 mass emissions rate (kg/MWh) is reported for each compliance period, along with the dates (year and month) of the first and twelfth operating months in the compliance period and the percentage of valid CO 2 mass emission rates obtained in the compliance period. The dates of the first and last operating months in the compliance period clearly bracket the period used in the determination, which facilitates auditing of the data. Reporting the percentage of valid CO 2 mass emis sion rates is necessary to demonstrate compliance with the requirement to obtain valid data for 95 percent of the operating hours in each compliance period. Any violations that occur during the quarter are identified. If there are no compliance periods that end in the quarter, a definitive statement to that effect must be included in the report. If one or more compliance periods end in the quarter but***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **592** of **763** 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 required under section 60.5555(a)(2) for affected EGUs. However, we will make the necessary modifications to the system in order to fully implement the reporting requirements of this rule upon promulgation. **XI. Consistency between BSER Determinations for This Rule and**  **the Rule for Existing EGUs.** In the CAA section 111(d) rule for existing steam units and combustion turbines that the EPA is promulgating at the s ame time as this CAA section 111(b) rule, the EPA is identifying 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 building block 3 (for steam units and combustion turbines, substitution of generation with new renewable energy). In this section, we explain why the EPA is not identifying building blocks 1, 2, or 3 as part of the BSER for new, modified, or reconstructed steam generators or combustion turbines. A. Newly constructed steam generating units. 1. Preference for technological controls.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **593** of **763** As discussed in this preamble and in more detail in the preamble to the CAA section 111(d) rule for existing sources, the phrase “system of emission reduction” is undefined and provides the EPA with discretion in setting a standard of performance under CAA section 111(b) or emission guidelines under CAA section 111(d). Because the phrase by its plain language does not limit our review of potential systems in either context, the same systems could be considered for application in new and existing sources . That said, many other factors and considerations direct us to focus on different 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 identifying, as the BSER, systems of emi ssion reduction that assure that these sources are inherently low
- emitting at the time of construction. There are several reasons for this approach to the BSER. While CAA section 111(b)(1)(B) and (a)(1) by their terms do not mandate that the BSER a ssure that new sources are inherently low emitting, that approach to the BSER is consistent with congressional intent for new sources, as expressed in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **594** of **763** legislative history. 553 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 run, the least expensive approach.” 554 Existing sources, on the other hand, would be regulated through emission standards, which were broadly understood at the time to reflect available technol ogy, alternative methods of prevention and control, alternative fuels, processes, and operating methods. 555 In 1977, Congress reinforced the distinction between new and existing source standards. Specifically, Congress amended the definition for a standard o f performance to clarify that new
553 Although Congress expressed a clear preference that new sources would be “designed, built, equipped, operated, and maintained so as to reduce emission s to a minimum, ” the Senate Committee Report also makes clear that the term standard of performance “refers to the degree of emission control which can be achieved through process changes, operation changes, direct emission control, or other methods .” Sen. Rep. No. 91
- 1196 at 15
- 17, 1970 CAA Legis. Hist. at 415
- 17 (emphasis added). 554 Sen . Rep. No. 91
- 1196 at 15
- 16, 1970 CAA Legis. Hist. at 416 (emphasis added). 555 See 1970 CAA Amendments , Pub. L. 91
- 604, § 4, 84 Stat. 1676, 1679 (Dec. 31, 1970) (describing information that the EPA must issue to the States and appropriate air pollution control agencies along with the issuance of ambient air quality criteria under Section 4 of the 1970 CAA titled “Ambient Air Quality and Emission Standards”).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **595** of **763** source standards would reflect the “best technological system of continuous emission reduction.” This new formulation was intended to compel new sources to install technological controls rather than implement lower
- cost compliance measures. In shifting new sources towards technological controls, Congress explained, lower
- cost measures would be available to existing sources where “higher capital costs could be avoided”. 556 As an example, Congress believed section 111 (following the 1977 CAA Amendments) would compel new coal - fired power plants to install scrubbers and take advantage of coal washing in order to free lower - sulfur coal ( i.e. , fuel switching) for use by existing units. The 1990 CAA Amendments repealed the provis ions in section 111(a)(1) that distinguished between new and existing sources, but nothing in the 1990 CAA Amendments precludes the EPA from continuing to prefer technological controls for new sources in order to ensure lower - cost measures would be availab le for existing sources. Indeed, this approach is sensible because new sources are expected to have long operating lives over which initial capital costs can be amortized. Thus, new construction is the preferred time to drive capital investment in emission controls.

556 H.R. Rep. No. 95
- 294 at 186, 1977 CAA Legis. Hist. at 2653.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **596** of **763** In this case, the BSER for new steam generators, partial CCS, requires substantial capital expenditures, which new sources are best able to accommodate. 2. Practical implications of including the building blocks . Even if the EPA cannot as a matter of interpretation prefer technological controls when setting new source standards, several practical considerations make the building blocks inappropriate for new sources. Thus, for the following 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 reasonable) costs on new steam- generating EGUs, and, as a result, 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 more difficult for new st eam- generating EGUs to compete with new nuclear units. Because the BSER is selected after considering cost (among other factors), the EPA is not required to, 557 and in this case believes it would not be appropriate to,

557 For example, as early as a 1979 NSPS rulemaking for affected EGUs, the EPA recognized that it was not required to establish as the BSER the most stringent adequately demonstrated system of emission reduction available , and instead could weigh 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 emissions below***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **597** of **763** select the most stringent adequately demonstrated system of emission reduction (through the combination of partial CCS and the building blocks) for purposes of setting a standard of performance under CAA section 111(b). Building block 1 measures are not appropriate (or would be redundant) because the BSER for new steam generating units is based on highly efficient supercritical technology, i.e., state of - the - art, efficient equipment. See section V.K above. Accordingly, there is little improvement in efficiency 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: New steam units would have a significantly limited range of options to implement building blocks 2 and 3. The new source performance standard was proposed and is being finalized as a rate
-based standard. Thus, if building blocks 2 and 3 were included in the BSER, a more stringent rate
based standard would be applicable to all new sources. However, it is conceivable that the EPA could propose a hybri d standard
those levels required to comply with standards of performance, 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 fact, the Act requires (or has potential for requiring) the imposition of a more stringent emission standard in several situations.”).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **598** of **763** that would include both an emission
- rate limit that reflects partial CCS and a requirement for allowances that reflects building blocks 2 and 3. Accordingly, the following discussion 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 program, 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, existing sources will have a range of measures to choose from. However, at least some of those methods may not be available to new sources, 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 important option for implementing the building blocks. There are large numbers of existing sources and they will become subject to the section 111(d) standards of performance at the same time. It may be more cost - effective for some to implement the building blocks than others, and, as a result, some may over - comply and some may under - comply, and the two groups may trade with each other. Because of the large numbers of existing sources, the trading market can be expected to be robust. Trading optimizes***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **599** of **763** efficiency. As a result, existing sources have more flexibility in the overall amount of their investment in building blocks 2 and 3, and can adjust investment obligations among themselves through emissions trading. In contrast, new sources construct one at a time, and it is unknown how many new sources there will be. Without a sizeable number of new sources, there will not be a robust trading market. Thus, a new source cannot count on being able to find a new source trading partner. In addition, it is not possible to count on new sources being able to trade with existing sources, for several reasons. First, there is legal uncertainty as to whether new sources could trade with existing sources under section 111. 558 Second, new sources must meet their standards of performance as soon as they begin operat ions. If they 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.

558 Part of the uncertainty lies in the distinctions between CAA section 111(b) and CAA se ction 111(d). While the EPA establishes nationally applicable performance standards for new sources, each state has considerable discretion in establishing standards of performance for existing sources. Accordingly, it is not clear that a new source rule c ould tap into existing source programs, particularly if that action would disrupt the operation of the state’s plan.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **600** of **763** In addition, for section 111(d) sources, we are granting a 7 - year period of lead- time for the implementation of the building blocks . This is due, in part, to the benefits of allowing the ERC and allowance market s to develop. However, the new source standards take effect immediately, so that new sources would not have the advantage of this lead time were they subject to more stringent standards reflected in the building blocks. 559 In addition, i f there are an unexpectedly large number of new sources, then they would be obliged to invest in greater amounts of building blocks 2 and 3, and that could reduce the amounts of building blocks 2 and 3 available for existing sources, and thereby raise the costs of buildi ng blocks 2 and 3 for existing sources. This could compromise the BSER under section 111(d) and undermine the ability of existing sources to comply with their section 111(d) obligations. 560

559 At least in theory, we could consider promulgating a standard of performance for new affected EGUs that becomes more stringent beginning in 7 years, based on a more stringent BSER. We are not inclined to adopt that approach because section 111(b)(1)(B) re quires that we review and, if necessary, revise the section 111(b) standards of performance no later than every 8 years anyway. 560 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 require technological controls for new combustion sources at least in part because this requirement would preclude new sources from relying on low
- sulfur coal to achieve their emission limits,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **601** of **763** B. New combustion turbines. For new combustion turbines, the buildi ng blocks are not appropriate as part of the BSER for the following reasons: Building block 1 is limited to steam generating units, and therefore has no applicability to new combustion turbines. Measures comparable to those in building block 1 would not be appropriate because the highly efficient NGCC construction already entails high efficiency equipment and operation. Building block 2 is also limited to steam generating units and is not appropriate as part of the BSER for new NGCC units because it would not result in any emission reductions. The reasons why building block 3 are not appropriate are the same as discussed above for why building blocks 2 and 3 are not appropriate for new steam generating units (limited range of options for implementation (incl uding lack of availability of trading), lack of lead
- time for implementation , and the possibility of reducing the availability of renewable energy for existing sources) . C. Modified and rec onstructed steam and NGCC units For modified and reconstructed ste am generators , the EPA identified the BSER as maintenance of high efficiency or implementation of a highly efficient unit. The resulting which, in turn, wou ld free up low- sulfur coal for existing sources.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **602** of **763** emission limit must be met over the specified time period and cannot be deviated from or averaged. As a result, a modif ied or reconstructed steam generator generally will require ongoing maintenance, and may find it prudent to operate below its limit as a safety margin. This represents a substantial commitment of
resources. For these units, the additional costs of implementing the building blocks would not be appropriate. In addition, building block 1 is not appropriate for modified or reconstructed steam generating units because the BSER for these units is already based on highly efficient 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 pe rformance. 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 modified 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 implementation (including lack of availability of trading), lack of lead
- time***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **603** of **763** for implementat ion, and the possibility of reducing the availability of renewable energy for existing sources) . **XII. Interactions with Other EPA Programs and Rules**  A. Overview This final rule will, for the first time, regulate GHGs under CAA section 111. In S ection IX o f the preamble to the proposed rule, the EPA addressed how regulation of GHGs under CAA section 111 could have implications for other EPA rules and for permits written under the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA Title V operating permit program. The EPA proposed to adopt provisions in the regulations that explicitly addressed some of thes e implications. For purpose of the PSD program, the EPA is finaliz ing provisions in part 60 of its regulations that make clear that the threshold for determining whether a PSD source must satisfy the Best Available Control Technology (BACT) requirement fo r GHG s continues to apply after promulgation of this rule . This rule does not require any additional revisions to State Implementation P lans. As discussed further below, this final rule may have bearing on the determination of BACT for new and existing and modified and reconstructed EGUs that require PSD permits. With respect to the Title V operating permits program, this rule does not affect whether sources are subject to the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **604** of **763** requirement to obtai n a title V operating permit based solely on emitting or having the potential to emit GHGs above major source thresholds . However, this rule does have some implications for t itle V fees, which the EPA is address ing in this final rule. Finally, the fossil fuel - fired EGUs covered in this rule are or will be potentially impacted by several other 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 to adopt regulatory language in 40 CFR part 60 that would ensure the promulgation of this NSPS would not undercut the application of rules that limit the application of the PSD permitting program requirements to only the large st sources of GHGs . An intervening decision of the United States Supreme Court has, to a large extent, resolved the legal issue that led the EPA to propose these Part 60 provisions. The Supreme Court has since clarifi ed that the PSD program does not apply to smaller sources based on the amount of GHGs they emit. However, because the largest sources emitting GHGs remain subject to the PSD permitting requirements, the EPA has concluded that it remains appropriate to adopt the proposed regulatory provisions in 40 CFR part 60 in this rule. We discuss our reasons for this action in detail***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **605** of **763** below.Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is requi red to obtain a preconstruction permit. This permit assures that the source meets specifi c requirements, including application of BACT to each pollutant subject to regulation under the CAA. Many states (and local districts) are authorized by the EPA to administer the PSD program and to issue 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 permitting program, EPA regulations contain a definition of the term “regulated NSR pollutant.” 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition contains four subparts, which cover pollutants regulated under various parts of the CAA. The second subpart covers pollutants regulated under section 111 of the CAA. The fourth subpart is a catch
- all provision that applies to “[a]ny pollutant that is otherwise subjection 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 EPA’s regulation of GHG emissions from motor***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **606** of **763** vehicle s , which first took effect on that same date. 75 FR 17004 (Apr. 2, 2010). As such , GHGs became subject to regulation under the CAA and the fourth subpart of the “regulated NSR pollutant” definition became applicable to GHGs . On June 3, 2010, the EPA issued a final rule, known as the Tailoring Rule, which phased in permitting requirements for GHG emissions from stationary sources under the CAA PSD and title V permitting programs (75 FR 3151 4). Under its understanding of the CAA at the time, the EPA believed the Tailoring Rule was necessary to avoid a sudden and unmanageable increase in the number of sources that would be required to obtain PSD and t itle V permits under the CAA because the sources emitted GHGs emissions over applicable major source and major modification thresholds. In Step 1 of the Tailoring Rule, which began on January 2, 2011, the EPA limited application of PSD or title V requirements to sources of GHG emissions only if the sources were subject to PSD or title V “anyway” due to their emissions of non - GHG pollutants. These sources are referred to as “anyway sources.” In Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA applied the PSD and title 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 emissions and to modifications of otherwise major sources that required a PSD permit because they increased***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **607** of **763** only GHG emissions above applicable levels in the EPA regulations. In the PSD program, the EPA implemented the steps of the Tailoring Rule by adopting a definition of the term “subject to regulation.” The limitations in Step 1 of the Tailoring Rule are reflec ted 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 GHG s would not be subject to PSD requirements unless the source 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” unless the source emits GHGs at or above this threshold. The Tailoring Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These provisions contain thresholds that, when applied through the definition of “regulated NSR pollutant,” function to limit the scope of the terms “major stationary source” and “major modification” that determine whether a source is required to obtain a PSD permit. See e.g. 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 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 limitations in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **608** of **763** Tailoring Rule would continue to apply to GHGs once they became regulated, through this final rule, under section 111 of the CAA. 79 FR at 1487
- 1488. As discussed above, the definition of “regulated NSR pollutant” in the PSD regulations contain s a separate PSD trigger for air pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the “NSPS trigger provision”). Thus, when GHG s become subject to a standard promulgated 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 GHG s from motor vehicles . However, the Tailoring Rule, on the face of its regulatory provisions, incorporated the revised thresholds it promulgated into only the fourth subpart of the PSD definition of regulated NSR pollutant (“[a]ny pollutant that otherwise is subject to regulation under the Act”) . The regulatory text does not clearly incorporate the thresholds into the NSPS trigger provision in the second subpart (“[a]ny pollutant that is subject to any standard promulgated under section 111 of the Act”). For this reason, a question arose as to whether the Tailoring Rule limitations would continue to apply to the PSD requirements after they are independently triggered for GHG s by the NSPS that the EPA is now promulgating . Stakeholders questioned whether the EPA must revise its PSD regulations

– - and, by the same token, whether states must revise their SIPs

– -***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **609** of **763** to assure that the Tailoring Rule thresholds will continue to apply to sources potentially subject to PSD under the CAA based
on GHG emissions. In the January 8, 2014 proposed rule, the EPA explained that the agency had included an interpretation in the Tailoring Rule preamble, which means that the Tailoring Rule thresholds continue to apply if and when the EPA promul gates requirements under CAA section 111. 79 FR at 1488 (citing 75 FR 31582). Nevertheless, to ensure there would be no uncertainty as to this issue, the EPA proposed to adopt explicit language in sections 60.46Da(j), 60.4315(b), and 60.5515 of the agency’ s regulations. The proposed language makes clear that the thresholds for GHGs in the EPA’s PSD definition of “subject to regulation” apply through the second subpart of the definition of “regulated NSR pollutant” to GHGs regulated under this rule . The EPA received comments supporting the adoption of this proposed language, but several commenters also expressed concern that adding this language to part 60 alone would not be sufficient. Several commenters urged 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 Ta iloring Rule limitations continued to apply after the adoption of CO 2 standards under CAA section 111 in this final rule.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **610** of **763** On June 23, 2014, the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection Agency, issued a decisi on addressing the application of PSD permitting requirements to GHG emissions. The Supreme Court hel d that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source (or modification thereof) for the purpo se of PSD applicability . The Court also said that the EPA could continue to require that PSD 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 effectively upheld PSD permitting requirements for GHG emissions under Step 1 of the Tailoring Rule for "anyway sources" and invalidated application of PSD permitting requirements to Step 2 sources based on GHG emissions. The Court also recognized that, although EPA had not yet done so, it could “establish an appropriate de minimis threshold below which BACT is not required for a source’s greenhouse gas emissions.” 134 S. Ct. at 2449. In accordance with the Supreme Court decision, on April 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) issued an amended judgment vacating the regulations that implemented Step 2 of the Tailoring Rule, but not the regulations that imp lement Step 1 of the Tailoring Rule. The court specifically vacated sections 51.166(b)(48)(v)***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **611** of **763** and 52.21(b)(49)(v) of the EPA’s regulations, but did not vacate sections 51.166(b)(48)(iv) or 52.21(b)(48)(iv). The court also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA, and, if so, to undertake such revisions. The practical effect of the Supreme Court’s clarification of the reach of the CAA is that it eliminates the need for Step 2 of the Tailoring Rule and subsequent steps of the GHG permitting phase in that EPA had planned to consider under the Tailoring Rule . This also eliminates the possibility that the promulgation of GHG standards under section 111 could result in additional
source s becoming subject to PSD based solely on GHGs, notwithstanding the limitations the EPA adopted in the Tailoring Rule. However, for an interim period, the EPA and the states will need to continue applying parts of the PSD definition of “subject to regulation” to ensure that sources obtain PSD permits meeting the requirements of the CAA . The CAA continues to require that PSD permits issued to “anyway sources” satisfy the BACT requirement for GHGs . Based on the language that remains applicable under sections 51.166(b)(48)(iv) and 52.21(b)(49)(iv), the EPA and state s may continue to limit the application of BACT to GHG emissions in those circumstances where a source emits GHGs in the amount of at least 75,000 tpy on a CO 2 e basis. The EPA’s intention is for***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **612** of **763** this to serve as an interim approach while the EPA moves forward to propose a GHG Significant Emission Rate (SER) that would establish a de minimis threshold level for permitting GHG emissions under PSD. Under this forthcoming SER rule, the EPA intends to propose restructuring the GHG provisions in its PSD regulations so that the de minimis threshold for GHGs will not reside within the definition of “subject to regulation.” This restructuring will be designed to make the PSD regulatory provisions on GHGs universally applicable, without regard to the particular subparts of the definition of “regulated NSR pollutant” that may cover GHGs . Upon promulgation of the SER rule , it will then provide a framework that states may use when updat ing their SIPs consistent with the Supreme Court decision. While the GHG SER rulemaking is pending, the EPA and approved state, local, and tribal permitting authorities will still need to implement the BACT requirement for GHGs . In order to enable permit ting authorities to continue applying the 75,000 tpy CO 2 e threshold to determine whether BACT applies to GHG emissions from an “anyway source” after GHGs are subject to regulation under CAA section 111, the EPA has concluded that it continues to be appropriate to adopt the proposed language in section 60.5515 (subpart TTTT) . Because the EPA is not finalizing the proposed regulations in subparts Da and KKKK, it***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **613** of **763** is not necessary to adopt the comparable provisions that the EPA proposed in sections 60.46Da(j) and 60.4315(b) The EPA has evaluated section 60.5515 in light of the Supreme Court decision and the comments received on the que stion of whether this CAA section 111 standard will undermine the application of the Tailoring Rule limitations. While most of the Tailoring Rule limitations are no longer needed to avoid triggering the requirement to obtain a PSD permit based on GHGs alone, the limitation in sections 51.166(b)(48)(iv) and 52.21(b)(49)(iv) will remain important to provide an 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 section 111 does not make this BACT applicability level for anyway sources effectively inoperable. The language in section 60.5515 will continue to be effective at avoiding this result after the judicial actions described above and the adoption of this final rule. The provisions in part 60 reference sections 51.166(b)(48) and 52.21(b)(49) of the EPA’s regulations. However, the courts have now vacated sections 51.166(b)(48)(v) and 52.21(b)(49)(v), and the EPA will take steps soon to eliminate these subparts from the C FR . As a result of these steps, the language of final section 60.5515 will not incorporate the vacated parts of sections 51.166(b)(48) and 52.21(b)(49), but these provisions in***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **614** of **763** part 60 will continue to apply to those subparts of the PSD rules that are needed on an interim basis to limi t 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 rule, the EPA is adopting the proposed text of section 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 revisions to the PSD regulations in part s 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 discuss ed above) the part 60 provisions adopted in this rule are sufficient to make 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 implications for PSD of regulating GHGs under CAA section 111, the EPA believes it will be most efficient for the EPA and the states if the EPA completes a comprehens ive PSD rule that will address all the implications of the Supreme Court decision. The revisions the EPA will consider based on the Supreme Court decision will***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **615** of **763** inherently address the commenters concerns about the definition of the “subject to regulation” and the proposed part 60 provisions. To the extent this PSD rule is not complete before the EPA proposes additional CAA section 111 standards for GHGs , the EPA will need to consider adding provisions like section 60.5515 to other subparts of part 60. In a separate rulemaking finalized concurrently with this rule, the EPA is also 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) standards. As of this time, the EPA has not proposed GHG standards for other source categories under CAA section 111. To the extent needed, this approach of adding provisions to a few subparts in part 60 would be less burdensome to states and more efficient than revising section 51.166 at this time solely to address the implications 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 address the implications of regulating GHGs under CAA section 111. However, the language in section 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 derived from the form of the pollutant described in regulations, such as***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **616** of **763** an NSPS, that make the pollutant regulated under the CAA. 56 FR 24468, 24470 (May 30, 1991); 61 FR 9905, 9912
- 18 (Mar. 12, 1996); 75 FR at 31522 . Moreover, it is more likely that states would need to consider a SIP revi sion if the EPA were to revise section 51.166 in this rule. Revisions to 51.166 can trigger requirements for states to revise their PSD program provisions under section 51.166(a)(6). Given the process required in states to review their SIPs and submit them to the EPA for approval, it is most efficient for all concerned when the EPA is able to consolidate its revisions to section 51.166. The EPA , thus , believes it will be less work for states if we issue a comprehensive set 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. In our proposal, we addressed any state with an approved PSD SIP program that applies to GHGs which believed that this final rule would require the state to revise its SIP so that the Tailoring Rul e thresholds continue to apply. First, the EPA encouraged any state that considered such revisions necessary to make them as soon as possible. Second, if the state could do so promptly, the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **617** of **763** EPA said it would assess whether to proceed with a separate rulema king action to narrow its approval of that state’s SIP so as to assure that, for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of the final NSPS rule. 79 FR 1487. The EPA did not receive any comments or other feedback from states requesting that the EPA narrow their program to ensure the Tailoring Rule thresholds 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 ensuring the Step 1 BACT applicability level for GHGs continues to apply on an interim basis. C. Implications for BACT Determinations under PSD New major stationary sources and major modifications at existing major stationary sources are required by the CAA to, among other things, obtain a permit under the PSD program before commencing construction. The emission thresholds that define PSD applicab ility can be found in 40 CFR 51 and 52 as discussed briefly in the preceding section. Sources that are subject to PSD must obtain a preconstruction permit that contains emission limitations based on application of BACT for each regulated NSR pollutant. The BACT requirement is set forth in section 165(a)(4) of the CAA,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **618** of **763** and in EPA regulations under 40 CFR parts 51 and 52. These provisions require that BACT determinations be made on a case
by- case basis. CAA section 169(3) defines BACT as: an emissions limitation (including a visible emission 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 stationary source or major modification which the Administrator, 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 methods, systems, and t echniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant.... Furthermore, this definition in the CAA specifies that “[i]n no event shall application of [BACT] result in emiss ions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 111 or 112 of the Act.” This condition of CAA section 169(3) has historically been interpreted to mean that BACT cannot be less stri ngent than any applicable standard of performance under the NSPS. See, e.g., U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 20
- 21 (March 2011) (“GHG Permitting Guidance”). Thus, upon completion of an NSPS, the NSPS establishes a “BACT Floor” for PSD permits that are issued to affected facilities covered by the NSPS. BACT is a case
-by- case review that considers a number of factors. These factors include the availability, technical feasibility, control effectiveness, and the economic,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **619** of **763** environmental and energy impacts of the control option. See GHG Permitting Guidance at 17
- 46. The fact that a minimum control requirement is established by the EPA through an applicable NSPS (i.e. the BACT floor) does not bar a permitting agency from justi fying a more stringent standard as BACT. In the proposed rule, the EPA discussed how this rule may relate to determination of BACT for new and existing EGUs that require PSD permits. Under this NSPS, an affected facility is a new EGU or a modified or reconstructed EGU. The new source NSPS requirements apply, in general, to any stationary source that adds a new EGU that is an affected facility under this NSPS. This could, for example, include both a new, greenfield EGU facility or an existing facility that wants to add a new EGU in order to add or replace capacity. While this latter scenario is considered a “new affected facility” under the NSPS, it may also be considered 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 modified or reconstructed sources as those terms are defined under part 60. It is important to recognize that a physical change that triggers the NSPS modification or reconstruction requi rements does not necessarily subject the source to PSD requirements, and vice versa. In general, in order to trigger the NSPS***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **620** of **763** modification or reconstruction requirements, a physical change must increase the maximum hourly emission rate of the pollutant (to be an NSPS modification) or the fixed capital cost of the change must exceed 50 percent of the fixed capital cost of a comparable entirely new facility (to be an NSPS reconstruction). See 40 CFR 60.2, 60.14, 60.15. Under the PSD program, however, a physical change (or change in the method of operation) must result in an increase in annual emissions of the pollutant by the specified emission threshold in order to be subject to PSD requirements. This emission calculation considers the unit’s past annual emis sion and its projected annual emissions. See, e.g., 40 CFR 52.21(a)(2)(iv)(C). In addition, the PSD emissions test for a modification allows the existing source to consider qualifying emission reductions and increases at the source within a contemporaneous period to “net out” of, or avoid, triggering PSD review. Thus, this NSPS could establish a BACT floor for sources that are modifying an existing EGU and their emissions make them subject to PSD. In the preamble to the proposed rule, the EPA discussed whether a standard of performance for the new source NSPS, specifically the BSER for solid fuel
- fired EGUs that is based on partial CCS, could become the BACT floor when permitting a modified or reconstructed EGU or non
-EGU source. As noted above, BACT is a ca se - specific review by a permitting agency. In***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **621** of **763** evaluating BACT, the permitting authority should consider all available control technologies that have the potential for practical application to the facility or emission unit under evaluation. 561 This 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. 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 Floor for new EGUs that would be inconsistent with prior BACT determinations for EGUs in both permits issued by EPA Regions and permits issued by state agencies on wh ich EPA has commented. Many of these comments were more directed at the development and deployment of CCS (i.e., the commenter did not believe CCS should be the basis for BSER) rather than examining whether an NSPS should establish the BACT floor for appli cable sources, which is the legal consequence of setting an NSPS under the terms of the CAA. 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 fuel - fired electric utility
s team generating units . 561 U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 24 (March 2011).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **622** of **763** With regard to the comment er s who stated that a BSER for EGUs that is based on partial CCS would be inconsistent with BACT determinations in previous GHG PSD permits, it is important to recognize that a BACT determi nation is a case
-by- case analysis and that technological capabilities and costs evolve over time. 562 In addition, t o date the EPA has not issued a PSD

562 In this regard, the 2011 GHG Permitting Guidance states that “although CCS is not in widespread use at this time, EPA generally considers CCS to be an ‘available’ add
- on pollution control technology for facilities emitting CO 2 in large amounts and industr ial facilities with high
-purity CO 2 streams.” GHG Permitting Guidance at 35. The Guidance goes on to note that CCS may not be available at modified sources, or in other specific circumstances. Id. at 36 (“While CCS is a promising technology, EPA does not believe that at this time CCS will be a technically feasible BACT option in certain cases.... The EPA recognizes the significant logistical hurdles that the installation and operation of a CCS system presents and that sets it apart from other add
- on control that are typically used ... Logistical hurdles for CCS may include obtaining contracts for offsite land acquisition ..., the need for funding..., timing of available transportation infrastructure, and developing a site for secure long term storage. Not every sour ce has the resources to overcome the offsite logistical barriers necessary to apply CCS technology to its operations, and smaller sources will likely be more constrained in this regard”); id. at 42
- 3 (noting that CCS may be expensive in individual instance s and thus eliminated as a control option for that reason under step 4 of the BACT analysis, noting further that revenues from EOR may offset other costs). See also UARG v. EPA, 134 S.Ct. 2427, 2448 (2014) (noting that EPA’s GHG Permitting Guidance states that carbon capture is reasonably comparable to more traditional, end
- of - stack BACT technologies, and that petitioners do not dispute that) **.** As explained at section V.I.5 above **,** in determining that partial CCS is BSER for new fossil fuel steam electric plants **,** EPA has carefully considered the issue of logistics***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **623** of **763** 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 determine whe ther the EPA
– as a PSD permitting authority

– has been either consistent or inconsistent with setting a BSER of partial CCS in thi s NSPS . Although some permitting authorities may have determined that CCS is not technologically feasible or economically achievable for a gas
- fired EGU, because of the
case -by- case nature of the analysis, it does not automatically follow that the same con clusion is appropriate for a solid fuel
fired EGU. Furthermore, PSD permitting requirements first applied to GHG s in January 2011 and more information about GHG control technology has been gained in this four
- and- a -half year period. Additionally, if a state was processing a permit application for a solid fuel
- fired EGU and CCS was not proposed as BACT (or not even considered as a possible control for BACT), (including cost estimates for land acquisition, transportation, and sequestration) and costs generally. Nor would new plants face the same types of constraints as modified or reconstructed sources in a BACT determination, since a new source has more leeway in choosing where to site . See text at V.G.3. above. Moreover, the GHG Permitting Guidance considered BACT determinations for all types of sources, not just those for which EPA has determined in this rule that partial CCS is the best system of emission reduction, and the concerns voiced in the Guidance thus must be considered in that broader context.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **624** of **763** the EPA is not necessarily required to comment negatively on the draft permit, or to otherwise request or require that the state agency amend the BACT to include CCS. For state agencies that have their own approved state implementation plan, the state has primacy over their permitting actions and discretion to interpret their approved rules and to apply the applicable federal and state regulatory requirements that are in place at the time 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 , if the EPA does not adversely comment on a certain permit or BACT determination, it does not necessarily imply EPA endorsement of the proposed permit or determination. Some commenters also felt that the determination of partial CCS as BSER is inconsistent with the agency’s position on CCS in the EPA’s GHG Permitting Guidance, which they say supports the notion that additional work is required before CCS can be integrated at full - scale electric utility applications. It is important to recognize that the EPA’s permitting guidance is guidance
- it does not contain any final determination of BACT for any source. Furthermore , we disagree with the commenters ’ characterization of the content of the GHG Permitting Guidance. The guidance specifically states “[f]or the purposes of a BACT analysis for GHGs, EPA classifies CCS as an add
- on pollution***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **625** of **763** control technology that is “available” for facilities emitting CO 2 in large amounts, including fossil fuel
- fired power plants, and for industrial facilities with high
-purity 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 top
- down BACT analysis for GHGs.” GHG Permitting Guidance at 32. As discussed elsewhere in the Guidance, technologies that should be listed in Step 1 are those that “have the potential for practical application to the emissions unit and regulated pollutant under evaluation.” GHG Permitting Guidance at 24. The EPA continues to stand by its position on the availability of CCS in this context, as expressed i n the GHG Permitting Guidance. The Guidance continues on to discuss case
- specific factors and potential limitations with applying CCS, and it acknowledges that CCS may not be ultimately selected as BACT in “certain cases” based on technology feasibility and cost. GHG Permitting Guidance at 36, 43. While acknowledging these challenges when it
was issued in March 2011, the Guidance clearly does not rule out the selection of CCS as BACT for any source category and it is forward looking. Nothing in the guidance is inconsistent with
agency’s present position that CCS is adequately demonstrated***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **626** of **763** for the types of sources covered by this rule, as articulated elsewhere in this preamble. A commenter asserted that the GHG Permitting Guidance should be amended because it calls for consideration of CCS in BACT determinations even though the proposed NSPS identified "partial CCS" as BSER for new boiler and IGCC EGUs. The guidance explains that “the purpose of Step 1 of the process is to cast a wide net and identify all control options with potential application to the emissions unit under review.” GHG Permitting Guidance at 26. The EPA agrees that the GHG Permitting Guidance only uses the term “CCS” and does not distinguish “partial CCS” from “full CCS.” But considering the purpose of Step 1 of the process, we believe that the term “CCS”, as it was used in the GHG Permitting Guidance, adequately describes the varying levels of CO 2 capture. A BACT review should analyze all available technologies in order to adequately support the BACT determination, and may require evaluation of partial CCS, full CCS, and/or no CO 2 capture. The specific facility type and CO 2 capture conditions will dictate the level(s) of CO 2 capture that are most appropriate to consider as “ available” in a BACT review. D. Implications for Title V Program Under the title V program, certain stationary sources, including “major sources” are required to obtain an operating***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **627** of **763** permit. This permit includes all of the CAA requirements applicable to the source, including adequate monitoring, recordkeeping, and reporting requirements to assure sources’ compliance. These permits are generally issued through EPA
approved State title V programs. In the January 8, 2014 proposal, the EPA discussed whether this rulemaking would impact the applicability of title V requirements to major sources of GHGs. 79 FR at 1489
- 90. The relevant issue for title V purposes was, in essence, whether promulgation of CAA section 111 requirements for GHGs would undermine the Ta iloring Rule, which, as explained above, phased in permitting requirements for GHG emissions for stationary sources under the CAA PSD and title V permitting programs. Based on the EPA’s understanding of the CAA at that time, the proposal discussed this iss ue in the context of the regulatory and statutory definitions of “major source , ” focusing on revisions that had been made in the Tailoring Rule to the definitions in the title V regulations of “major source” and “subject to regulation.” 79 FR at 1489
- 90 (quoting 75 FR 31,583). Under the title V regulations, as revised by the Tailoring Rule, “major source” is defined to include, in relevant part, “a major stationary source ... that directly emits , or has the potential to emit, 100 tpy or more of any air pollut ant subject to regulation.” The proposal further explained that the GHG***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **628** of **763** threshold that had been established in the Tailoring Rule had been incorporated into the definition of “subject to regulation” under 40 CFR 70.2 and 71.2, such that those definitions specify

“ ‘that GHGs are not subject to regulation for purposes of defining a major source, unless as of July 1, 2011, the emissions of GHGs are from a source 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 title V definition of “major source , ” as revised by the Tailoring Rule, did not on its face distinguish among types of regulatory triggers for title V. It further noted that the title V program had already been triggered for GHGs, and thus concluded that the promulgation of CAA section 111 requirements would not further impact title V applicability requirements for major sources of GHGs. 79 FR at 1489
- 90. As noted elsewhere in this section, after the proposal for this rulemaking was published, the United States Supreme 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 Protection Agency, Nos. 09
- 1322, 10
- 073, 10
- 1092 and 10
- 1167 (D.C. Cir., April 10, 2015). Those decisions support the same overall conclusion as the EPA discussed in the proposal, though for different reasons.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **629** of **763** With respec t to title V, the Supreme Court said in UARG v EPA that EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a title V operating permit. In accordance with that decision, the D.C. Circuit’s amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, vacated the title V regulations under review in that case to the extent that they require a stationary source to obtain a title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. The D.C. Circuit also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA, and, if so, to undertake to make such revisions. These court decisions make clear that promulgation of CAA section 111 requirements for GHGs will not result in EPA imposing a requirement that stationary sources obtain a title V permit solely because such source s emit or have the potential to emit GHGs above the applicable major source thresholds. 563

563 As explained elsewhere in this notice, the EPA intends to conduct future rulemaking action to ma ke the appropriate revision s to the operating permit rules to respond to the Supreme Court decision and the D.C. Circuit’s amended judgment. To the extent there are any issues related to the potential interaction between the promulgation of CAA section 111 requirements for GHGs and title V applicability based on emissions above major source thresholds, the EPA expects there***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **630** of **763** To be clear, however, unless exempted by the Administrator through regulation under CAA section 502(a), any source , including an area source (a “non
-major source”), subject to an NSPS is required to apply for, and operate pursuant to, a title V permit that assures compliance with all applicable CAA requirements for the source, including any GHG
- related applicable requirements. This aspect of the title V program is not affected by UARG v. EPA, as the EPA does not read that decision to affect either the grounds other than those described above on which a title V permit may be required or the applicable requirements that must be addressed in title V permits. 564 Consistent with the proposal, the EPA has concluded that this rule will not affect non
-major sources and there is no need to consider whether to exempt non
-major sources. Thus, sources that are subject to the CAA section 111 standards promulgated today are required to apply for, and operate pursuant to, a title V permit that assures compliance with all would be an opportunity to consider those during that rulemaking. 564 See Memorandum from Janet G. McCabe, Acting Assistant Administrator, Office of Air and Radiat ion, and Cynthia Giles, Assistant Administrator, Off ice of Enforcement and Compliance Assurance, to Regional Administrators, Regions 1
- 10, Next Steps and Preliminary Views on the Application of Clean Air Act Permittin g Programs to Greenh ouse Gases Following the Supreme Court’s Decision in Utility Regulatory Group v. Environmental Protection Agency (July 24, 2014) at 5.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **631** of **763** applicable CAA requirements, including any GHG
- related applicable requirements. E. Implications for Title V Fee Requirements for GHGs 1. Why is the EPA revising Title V fee rules as pa rt 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 re quirements of the 40 CFR part 70 and part 71 operating permit rules under Title V of the CAA to avoid inadvertent consequences 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 NSPS standards for GHGs, then approved part 70 programs implemented by state, local and tribal permitting authorities 565 that rely on the “presumptive minimum” approach and the part 71 program 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 believes this would result in the collection of fees in excess of what is

565 Hereafter, for the sake of simplicity, we will general ly refer to part 70 permitting authorities as “state” permitting authorities and refer to part 70 programs as “state” programs.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **632** of **763** required to cover the re asonable costs of an operating permit program. See NSPS proposal at 1490. In response to these concerns, the EPA proposed regulatory changes to limit the fees collected based on GHG emissions and proposed two fee adjustment options to increase the fee s collected based on the costs for permitting authorities to conduct certain review activities related to GHG emissions , while still providing sufficient funding for an operating permit program . Also, we proposed an option that would have provided for no fee adjustments to recover the costs of conducting review activities related to GHG emissions . Id . at 1490. The EPA did not propose any action related to state and local permitting authorities that do not use the presumptive minimum approach. Most c ommenters on the proposal , including state and local permitting authorities, were supportive of exempting GHGs from the emissions
-based fee calculations of the permit rules , but support for the fee adjustment options was mixed, with state and local permitting authorities generally supporting either of the two fee adjustments , and other commenters generally supporting the option that provide s for no fee adjustment . 2. Background on the Fee Requirements of Title V In the NSPS proposal, the EPA explained the statuto ry and regulatory background related to the requirement that permitting authorities collect fees from the owner or operator of title V***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **633** of **763** sources that are sufficient to cover the costs of the operating permit program. CAA section 502(b)(3)(A) requires an operating permit program to include a requirement 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 permit program, the permitting authority must show “the program will result in the collection, in the aggregate, from all sources [required to get an operating permit] , of an amount not less than $25 per ton of each regulated pollutant [adjusted annually for changes in the consumer price index], or such other amount as the Administrator may determine adequately reflects the reasonable costs of the permit program. ” See also 40 CFR 70.9(b)(2). This has been generally referred to as the “presumptive minimum” approach. If a permitting authority does not wish to use the presumptive minimum approach, it may demonstrate “that collecting an amount less than the [presumptive minimum 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 s ection 502(b) (3)(B)(ii) sets forth a definition of “regulated pollutant” for purposes of calculating***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **634** of **763** the presumptive minimum that includes each 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 the definition of “regulated pollutant” for purposes of operating permit fee calculations (“the GHG exemption”). The EPA then proposed two alternative ways to account for the costs of addressing GHGs in operating permits through a cost adjustment. First, we proposed a modest additional cost for each GHG
- related activity of certain types that a permitting authority would process (“the GHG adjustment option 1”). Alternatively, we proposed a modest additional increase in the per ton rate used in the presumptive minimum calculation for all non
- GHG fee pollutants (“the GHG adjustment option 2”). The EPA also solicited comment on an option that would provide no additional cost adjustment to account for GHGs (“the GHG adjustment option 3”). All of the GHG adjustment options are based on the assumption that the GHG exemption is finalized. See NSPS Proposal at 1493
- 1495. The EPA additionally proposed two clarif ications. The 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 clarification”). Id . at 1505, 1506 and 1511. The second was a proposal to move***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **635** of **763** the existing definition of “Greenhouse gases (GHGs)” within 40 CFR 70.2 and 71.2 to promote clarity in the regulations (“the GHG clarification”). Id. at 1490, 1517, 1518. For background purposes, below is a brief summary of each of the proposals.
a. The GHG exemption . To address the fee issues discussed in the NSPS proposal, the EPA proposed to exempt GHG emissions from the definition of “regulated pollutant (for presumptive fee calculation)” in 4 0 CFR 70.2 and the definition of “regulated pollutant (for fee calculation)” in 40 CFR 71.2. 566 See NSPS preamble at 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 process (an activity
-based adjustment). The three activities identified for this option were “GHG completeness determination (for initial permit or for updated application)” at 43 hou rs of burden, 567 “GHG evaluation for a modification or related permit action” at 7 hours of burden, and

566 Hereafter we will refer to these definitions as the “fee pollutant” definitions. Also, note that both fee pollutant definitions cross - reference the definitions of “regulated air pollutant” which includes air pollutants “subject to any standard promulgated under section 111 of the Act.” 567 Burden is the hours of staff time necessary to perform a task.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **636** of **763** “GHG evaluation at permit renewal” at 10 hours of burden. See also 79 FR 1494, fn. 280 (providing 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) specific to the state, including wages, benefits, and overhead, to determine the cost of each activity. All the activities for a given period would be totaled to dete rmine the total GHG adjustment for the state. See 79 FR at 1494. For part 71, we proposed a labor rate assumption of $52 per hour in 2011 dollars. Using that labor rate, we proposed to determine the GHG fee adjustment for each GHG permitting program activity to be a specific dollar amount for each activity (“set fees”) that the source would pay for each activity performed. See 79 FR at 1495. The EPA proposed to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this option.
c. The GHG adjustment option 2 . The second proposed GHG adjustment option (option 2) was to increase the dollar per ton ($/ton) rates used in the fee calculations for each non
- GHG fee pollutant. The revised $/ton rates would be multiplied by the total tons of non - GHG fee poll utants actually emitted by any source to determine the applicable total fees. The EPA proposed***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **637** of **763** to increase the $/ton rates by 7 percent. 568 See NSPS proposal at 1494, 1495. d. The GHG adjustment option 3 . The EPA also solicited comment on not charging any fe es related to GHGs (option 3). The basis for this proposed option was the observation that most sources that need to address GHGs in a permit would also emit non
- GHG fee pollutants, and thus, the cost of permitting for any particular source may be accounte d for adequately without charging any additional fees related to GHGs. Id. at 1494
- 1495.
e. The fee pollutant clarification . Another fee - related proposal was to add regu latory text to 40 CFR pa rt 60, s ubparts Da, KKKK and TTTT, to clarify that the fee pollutant for operating permit purposes would be considered to be “GHGs,” (as defined in 40 CFR 70.2 and 71.2), 569 rather than solely CO 2 , which would be regulated under the section 111 standards and implemented through the EGU GHG NSPS. Id . at 1505, 1506, and 1511.

568 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 September 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. 569 Note that in 40 CFR §70.2 and §71.2, the term “ Greenhouse gases (GHGs)” is defined as the “aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.”***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **638** of **763** 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 definition within those sections to promote clarity in the regulations. Id. at 1490, 1517, 1518. 4. What action is the EPA finalizing? In this action, the EPA is finalizing the following elements as proposed: (1) the GHG exemption, (2) the GHG adjustment option 1, and (3) the fee pollutant clarification. Public commenters on the proposal stated both support and opposition to using the NSPS rulemaking action to revise the title V fee rules. Two commenters state d that propos ing the title V fee revision s within the NSPS rulemaking would result in fewer commenters , particularly state and local permitting authorities, having knowledge of the changes to the fee rule s and sufficient opportunity to comment on the changes because the NSPS proposal is limited to a single source category, and one stated that a separate proposal for the fee rules would provide a sufficient opportunity for public comment . The EPA believes it is appropriate to move forward with final action amending the title V fee regulations as part of this NSPS. As we explained in the preamble for the proposal and elsewhere in this final rule, the fee rules and the section 111 standards are interrelated because, if we do not revise the fee rules, promulgation of the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **639** of **763** final NSPS will trigger certain requirements related to title V fees for GHG emissions that the EPA believes will result in the collection of excessive fees in states that implement the presumptive mi nimum approach and in the part 71 program. Thus, it is important to finalize the revisions to the fee rules at the same time or prior to this NSPS, and it is within the EPA’s discretion to address the NSPS and the fee rules at the same time as part of the same rulemaking action. In response to the commenters who were concerned that including the fee rule proposal as part of the NSPS proposal would result in the public not having sufficient public comment opportunities , the EPA believes sufficient public comment opportunit ies were provided on the fee rule changes because the proposal met all public participation requirements and we provided additional public outreach, including to state and local permitting authorities , which discussed the fee rule proposal . In addition to the publication of the proposed rulemaking in the Federal Register, the EPA held numerous hearings, reached out to state partners and the public, and developed numerous fact sheets and other information to support public comment on this rul e. The EPA has complied with the applicable public participation requirements and executive orders. The proposal met all the requirements for public notice

– it contained a clear and detailed explanation of how the part 70 and 71 rules would be affected by the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **640** of **763** promulgation of the CAA section 111 standard for EGUs and how the EPA proposed to revise the related regulatory provisions. We received many comments on the proposal to revise the fee rule for operating permits programs , and we are taking those comments into consideration in the finalization of the rulemaking action.
a. The GHG exemption . The EPA is taking final action to revise the definition of regulated pollutant (for presumptive fee calculation) in 40 CFR 70.2 and regulated pollutant (for fee calcu lation) in 40 CFR 71.2 to exempt GHG emissions. This regulatory amendment will have the effect of excluding GHG emissions from being subject to the statutory ($/ton) fee rate set for the presumptive minimum calculation requirement of part 70 and the fee ca lculation requirements of part 71. We received supportive comments 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 in the proposal notice, including that leaving these regulations unchanged would have resulted in the collection of fee revenue far beyond the reasonable costs of an operating permit program. The EPA believes that these revisions (in conjunction with the GHG adjustment, see below) are***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **641** of **7 63**  consistent with the CAA requirements for fees pursuant to the authority of section 502(b)(3)(B)(i). Some members of the public opposed the proposed GHG exemption for reasons including that it may limit permitting authorities’ ability to charge sufficient fees to cover the cost of GHG permitting 570 if the state is barred from exceeding minimum requirements set by the EPA. Despite this adverse comment, the EPA believes it is appropriate to finalize the GHG exemption because we are not finalizing any requirements that would require states to charge any particular fees to any particular sources. The changes we are finalizing to part 70 concern the presumptive minimum approach, which sets a minimum fee target for states that have decided to follow the presumptive minimum approach. Neither the statute nor the final rule require any state following the presumptive minimum 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 programs however they see fit in order to meet the requirement that they colle ct revenue sufficient to cover all reasonable costs of

570 We use the term “ GHG permitting ” in this section of the notice to refer to measures undertaken by permitting authorities to ensure that GHGs and any applicable requirements related to GHGs are appropriately addressed in title V permitting.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **642** of **763** their permitting program. See CAA section 502(b)(3); 40 CFR 70.9(b)(3). b. The GHG adjustment option 1 . The EPA is finalizing GHG adjustment option 1 because we believe it will result in a system for the calculation of costs for part 70 and fees for part 71 that is most directly related to the costs of GHG permitting. The EPA has determined that some adjus tment to cost and fee accounting is important because the recent addition of GHG emissions to the operating permitting program does add new burdens for permitting authorities. Although GHG adjustment option 3 (no GHG permitting fee adjustments) was support ed by many industrial commenters, the EPA rejected it because it is in tension with the statutory requirement that permitting authorities collect sufficient fees to cover all the reasonable costs of permitting. See CAA section 502(b)(3)(A). Some state and local permitting authorities provided comments supporting option 1, while other s support ed 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 EPA, but that they believed would be appropriate for their program . The EPA is finalizing option 1 instead of option 2 because the option 1 adjustments are based on the actual costs for***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **643** of **763** permitting authorities to process specific actions that require GHG reviews. The option 2 approach, which would have added a 7 percent surcharge to the $/ton rate used in the fee
- related calculations, may have been administratively easier to implement, but is tied to the emissions of non
- GHG air pollutants, which are not directly related to the costs 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 calculations and accounting for the GHG permitting costs through option 1 will result in fees that will cover the reasonable costs of the permitting programs. The EPA is revising the part 70 regulations through this final action, specifically 40 CFR 70.9(b)(2), to modify the presumptive minimum approach to add the activity
-based cost of GHG permitting activities, outlined in the revised 40 CFR 70.9(b)(2)(v), to the emissions
-based calculation of 40 CFR 70.9(b)(2)(i), which is being revised to now exclude GHG emissions. To determine the activity
-based GHG adjustment under 40 CFR 70.9(b)(2)(v), the permitting authority will multiply the burden hours for each activi ty (set forth in the regulation) by the cost of staff time (in $ per hour), including wages, benefits, and overhead, as determined by the state, for the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **644** of **763** particular activities undertaken during the particular time period. States that implement the presumptive minimum approach will need to follow the final rule’s option 1 approach. 571 States that use the detailed accounting approach are not directly affected by this rulemaking, but they must ensure that their fee collection programs are sufficient to fully fund all reasonable costs of the operating permit program, including costs attributable to GHG- related permitting. The EPA suggests states that use the detailed accounting approach consider the 7 percent assumption for the costs of GHG permitting in any such analysis, consistent with the EPA analysis of options 1 and 2 in the proposal . Consistent with 40 CFR 70.4(i), a state that wishes 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 formal program revision pro cess is needed and will inform the state of next steps. The communication apprising the EPA of any such changes

571 A presumptive minimum state may require various changes to its approved operating permit program before it may begin to implement the option 1 approach. For example, its regulations, and/or program proce dures and practices, may need to be revised, depending on the structure of the fee provisions in the state’s program; thus, the exact response necessary to address this final action may vary from state to state .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **645** of **763** should include at least a narrative description of the change and any other information that will assist the EPA in its assessment of the signif icance of the changes. Certain changes, such as switching from the presumptive minimum method to a detailed accounting method, will be considered substantial program revisions and be subject to the requirements of 40 CFR 70.4(i)(2). With respect to the pa rt 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 activity
based fee of 40 CFR 71.9(c)(8) and the emissions
-based fee of 40 CFR 71.9(c)(1)
- (4) 572 , 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 activity that has been initiated since the fee was last paid. Under part 71, fees are typically paid at the time of in itial application submittal, and thereafter, annually on the anniversary of the initial fee payment, or on any other dates that may be established in the

572 Note that the emissions
-based fee calculation differs somewhat depending on whether the part 71 program is being implemented by the EPA ( see 40 CFR §71.9(c)(1 ) ) ; a state, loca l or tribal agency with delegated authority from the EPA ( see §71.9(c)(2 ) ) ; the EPA with contractor assistance ( see §71.9(c)(3 ) ) ; or an agency with partial delegation authority ( see §71.9(c)(4 ) ) .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **646** of **763** permit. These set fees would not change until such time as we may revise our part 71 rule to change the set fees. The final rule implements the option 1 approach by listing three activities performed by permitting authorities that involve GHG reviews. The following describes the activities as described in our proposal and certain clarifications we are
ma king in the final rule to ensure consistent implementation. The EPA is finalizing that the first listed activity under option 1 is “GHG completeness determination (for initial permit or updated application).” This activity must be counted for each new ini tial permit application, even for applications that do not include GHGs emissions or applicable requirements, since an important part of any completeness determination will be to determine that GHG emissions and applicable requirements have been properly addressed, as needed, in the application. 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 determination will be adequate to cover the reasonable costs for a permitting authority to review an initial application and any subsequent application updates related to initial permit issuance; 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 addition to***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **647** of **763** the completeness determination for the initial application. This is an important distinction because many sources submit multiple permit application updates, either voluntarily or as required by the permitting authority, during application review, many of which do not require a separate or comprehensive completeness determination. The EPA is finalizing regulatory text that would describe the second listed activity a s “GHG evaluation for a permit modification or related permit action.” 573 The EPA had proposed that the second listed activity under option 1 would be “GHG evaluation for a modification or related permit action.” For the final rule, we are clarifying that we are adding a cost for a “permit modification” rather than for a “modification.” The term “modification” may be interpreted to refer to any change at a source, even a change that would not be required to be processed as a “permit modification,” while “permit modification” refers to any revision to an operating permit that cannot be processed as an administrative permit amendment and thus requires a review

573 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 amendments are not defined as “permit modifications” in the permit rules. See, e.g., 40 CFR §§70.7(d), (e), and (f).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **648** of **763** by a permitting authority as either a significant or minor permit modification. The EPA is finalizing the third activity as “GHG evaluation at permit renewal.” This activity covers the processing of all permit renewal applications and will involve evaluations of whether any GHG applicable requirements are properly included. Some members of the public commented that finalizing a GHG adjustment would inappropriately increase sources’ financial burdens. The EPA has explained, both in the proposal notice and elsewhere in this preamble, the importance of the fee
- related revisions to account for the costs associ ated with GHG
- related permitting. The EPA believes that the revisions being finalized will result in modest and reasonable fee increases necessary to cover states' increased costs. 574 To the extent that commenters intended to argue that the adjustments we proposed would exceed the actual costs of GHG permitting, no commenters provided any information or analysis to support that position. Some commenters did state that the costs associated with GHG
- related permitting should be minimal because few applicable re quirements will apply to GHGs. As stated earlier in this notice, EPA’s cost estimate for the proposal concerned the incremental costs of GHG
574 The EPA estimated in the proposal that option 1 would result in about a 7 percent overall increase in the annual part 70 fees that are collected by all permitting authorities nationally. See 79 FR at 1494.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **649** of **763** permitting for any source, not just those that would have, at the time of the analysis, triggered the requirement t o get a permit based on GHG emissions or applicable requirements. Despite some comments received to the contrary, the EPA does not believe it is appropriate to delay the finalization of the GHG adjustment. The EPA does not believe such delays would be c onsistent 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 cover the increased costs. The regulatory changes being finalized in this action p rovide the states with optimal flexibility and sufficient funding to implement their GHG permitting programs. Some commenters had specifically stated that the EPA should delay finalization of this rule until the completion of the next ICR renewal process. While we do not believe delaying this rule is appropriate, as explained above, the EPA notes that we remain committed to collecting and analyzing additional data on costs attributable to GHG permitting for operating permit programs. We may adjust the GHG c ost adjustments in future rulemakings if necessary to comply with the requirements of the Act. As an alternative to the options proposed by the EPA, 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 approach of the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **650** of **763** final rule will be more equitable for sources and more representative of actual costs because option 1 considers the costs of the actual permitting activities performed by a part icular permitting authority, while any emissions
-based approach would not be as directly related to actual costs incurred by permitting authorities. Some commenters alleged that EPA’s proposal on adjustments to the operating permit programs was vague. 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 explained in the proposal that support for the cost adjustment for GHGs under option 1 is contained in several analyses performed by the EPA and approved by the OMB related to the effect of the addressing GHG requirements in operating permits. These analyses have been placed in the docket for this rulemaking. The analyses include: the Regulatory Impact Assessment (RIA) for the Tailoring Rule (see Regulatory Impact Analysis for the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report, May 2010); the part 70 ICR change request for the Tai loring Rule (which was based on the RIA for the Tailoring Rule); and the current ICR for part 70 (EPA ICR number 1587.12; OMB control number 2060

– 0243).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **651** of **763** Several commenters asked that we make changes to the option 1 approach that we proposed, such as addi ng new activities or decreasing the costs we assumed for the proposal. In response to these comments, we note that we received no quantitative data or other information from commenters that we believe demonstrates the need to revise the list of activities we included under option 1 or the burden hour assumptions under option 1 for the activities. Note that to promote consistent implementation of the final option 1 approach, the preamble describes elsewhere a few clarifications concerning the activities unde r option 1 and one minor revision to the regulatory text of one of the activities. Since the EPA’s proposed rulemaking, the Supreme Court decided in UARG v. EPA that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a title V operating permit. 575 The EPA’s review of the effect of the Supreme Court decision on

575 The EPA does not, however, read the UARG decision to affect other grounds on which a title V permit may be required or the applicable requirements that must be addressed in title V permits. See Memorandum from Janet G. McCabe, Acting Assistant Administrat or, Office of Air and Radiation, and Cynthia 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 Air Act Permitting Programs to Greenhouse Gases Following the Supreme Court’s Decision in Utility Regulatory Group v. Environmental Protection Agency (July 24, 2014) at 5.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **652** of **763** the burden hour assumptions for the GHG review activities under proposed option 1 is that the effects are not significant enough to warrant revision of the burden hour assumptions in the final rule . Proposed option 1 was based on the assumption that permitting authorities would need to evaluate all permit applications for initial permit issuance, significant and minor permit modifications , and permit 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 issues for sources applying for a title V permit and for permit modifications and renewals for existing permits , and we do not anticipate that the decision will significantly affect the total number of such evaluations that will occur in any given year compared to the assumptions in our analysis, which as explained above, were based on the incremental costs of GHG permitting for any source . Thus , we are finalizing the burden hour assumptions as they were proposed. See NSPS proposal at 1494 and the supporting statement for the 2012 part 70 ICR renewal . Al so, as discussed previously, we remain committed to collecting and analyzing additional data on costs and we may adjust 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 text within 40 CFR part 60, subpart TTTT,***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **653** of **763** to clarify that the fee pollutant for operating permit purposes is GHG (as defined in 40 CFR 70.2 and 71.2). We are finalizing these provisions to add clarity to our regulations and to avoid the potential need for possible future rulemaking s to adjust the title V fee regulations 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 cl arifying text to 40 CFR pa rt 60, s ubparts Da, KKKK and TTTT. The final rule adds the clarification text only to subpart TTTT because the EPA is codifying all of the requirements for the affected EGUs in a new subpart TTTT and including all CO 2 emission standards for the affected EGUs (electric utility steam generating units, as well as natural gas - fired stationary combustion turbines) in that newly created subpart. See S ection III.B of this preamble for more on this subject. d. The GHG clarific ation . The EPA is taking no action at this time on the proposal to move the definitions of “Greenhouse gases (GHG)” within the definition of “Subject to regulation” in 40 CFR parts 70 and 71. No public comment s were received on this proposed clarification; however, subsequent to the proposal, on June 23, 2014, the Supreme Court in UARG v . EPA decided that GHG emissions could not be used in making certain applicability determinations under the operating permit ru les. More specifically with respect to title V, as described above, the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **654** of **763** Supreme Court said that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a title V operating permit. In accordance with 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 regulations under review in that case to the extent that they require a stationary source to obtain a title V permit solely because the source emits or has the potential to emit GHGs above the applicable ma jor source thresholds. The D.C. Circuit also directed the EPA to consider whether any further revisions to its regulations 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 conduct 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 proposal to move the definitions of GHGs within the operating permit rules. F. Interactions with Other EPA Rules Fossil fuel
- fired EGUs are, or potentially will be, impacted by several other recently finalized or proposed EPA***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **655** of **763** rules. 576 Many of the rules that impact fossil fuel
- fired EGUs apply to existing facilities as well as newly constructed, modified, or reconstructed facilities . In fact, the rules described below are more applicable to existing EGUs than to
newly constructed , modified, or reconstructed EGUs. Although those rules will affect EGUs as existing sources, because we expect that there will be few NSPS modifications or reconstructions , we don’t anticipate those rules affect ing EGUs as modified or reconstructed source s . In constructing 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 from new and existing coal
- and oil
- fired EGUs. The MATS rule will reduce emissions of heavy metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel (Ni); and acid gases, including hydrochloric acid (HCl) and hydrofluoric aci d (HF). These toxic air pollutants, also known as hazardous air pollutants or air toxics, are known to cause, or suspected of causing, damage

576 We discuss other rulemakings solely for background purposes. The effort to coordinate rulemakings is not a defense to a violation of the CAA. Sources cannot defer compliance with existing requirements because of other upcoming regulations.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **656** of **763** nervous system damage, cancer, and other serious health effects. The MATS rule will also reduce SO 2 and fine parti cle pollution, which will reduce particle concentrations in the air 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 commence construction or reconstruction after May 3, 2011) subject 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 required to begin meeting the rule’s requirements on April 16, 2015. Controls that will achieve the MATS performance standards are being installed on many units. Certain units, especially those that operate infrequently, may be considered not worth investing in given today’s electricity market, and are closing. The final MATS rule provided a foundation on which states and other permitting authorities could rely in granting an additional, 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 receive an administrative order that includes a compliance schedule of up***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **657** of **763** to an additional year, if it is needed to ensure electricity reliability. 577 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 (NOX ) emissions that cross state lines. These pollutants react in the atmosphere to form fine particles and ground
- level ozone and are transported long distances, making it difficult for other states to attain and maintain the NAAQS. The first phase of CSAPR became effective on January 1, 2015, for SO 2 and annual NOX , and May 1, 2015, for ozone season NOX . The second phase will become effective on January 1, 2017, for SO 2 and annual NOX , and May 1, 2017, for ozone season NOX . Many of the power plants participating in CSAPR have taken actions to reduce hazardous

577 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 hazardous 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 dissent was filed because the EPA did not con sider cost when determining 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 not considering cost when determining that regulation of EGUs was "appropriate" pursuant to section 112(n)(1). The Supreme 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
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– Do Not Cite, Quote or Release During Review *** Page **658** of **763** air pollutants for MATS compliance that will also reduce SO 2 and/or NOX . In this way these two rules are complementary. Compliance with one helps facilities comply with the 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 rule was published on August 15, 2014 (79 FR 48300; August 15, 2014), and became effective October 14, 2014. The 316(b) rule establishes new standards to reduce injury and death of fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. 578 The 316(b) rule subje cts existing power plants and manufacturing facilities that withdraw in excess of 2 million gallons per day (MGD) of cooling water, and use at least 25 percent of that water for cooling purposes, to a national standard designed to reduce the number of fish destroyed through impingement and entrainment. Existing sources subject to the 316(b) rule are required to comply with the impingement requirements as soon as practicable

578 CWA section 316(b) provides that standards applicable to point sources under sections 301 and 306 of the Act must require that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **659** of **763** after the entrainment requirements are determined. They must comply with applicable site
- specific entrainment reduction controls based on the schedule of requirements established by the permitting authority. Additional information regarding the 316(b) rule for existing sources i s included in section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with this rule. Although the recently issued 316(b) rule discussed here applies to existing sources, there are also 316(b) technology-based standards for new sources wi th cooling water intake structures. 4. Disposal of Coal Combustion Residuals from Electric 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 c omprehensive set of requirements for the safe disposal of coal combustion residuals (CCRs), commonly known as coal ash, from coal - fired power plants. The CCR rule establishes technical requirements for existing and new CCR landfills and surface impoundment s under Subtitle D of the Resource Conservation and Recovery Act (RCRA) , the nation's primary law for regulating solid waste. New CCR landfills and surface impoundments are required to meet the technical criteria before any CCR is placed into the unit. Existing CCR surface***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **660** of **763** impoundments and landfills are subject to implementation timeframes established in the rule for the individual 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 finalizing along with this rule . 5. Steam Electric Effluent Limitation Guidelines and Standards (SE ELG Rule) The EPA is reviewing public comments and working to finalize the proposed SE ELG rule which will impact fossil fuel
fired EGUs. In 2013, the EPA proposed the SE ELG rule ( 78 FR 34432 ; June 7, 2013) to strengthen the controls on discharges from certain steam electric power plants by revising technology
based effluent limitations guidelines and standards for the steam electric power generating point source category. The proposed regulation, which includes new requirements for both existing and new generating units, would reduce impacts to human health and the environment by reducing the amount of toxic metals and other pollutants currently discharged to surface waters from power plants. The EPA intends to take final action on the proposed rule by September 30, 2015. Section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **661** of **763** 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 assuring a reliable power system. Executive Order (EO) 13563, “Improving Regulation and Regulatory Review,” issued on January 18, 2011, states that “[i]n develop ing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote... coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are desi gned to promote innovation.” Within the EPA, we are paying careful attention to the interrelatedness and potential impacts on the industry, reliability and cost that these various rulemakings can have. As discussed in earlier sections of this preamble, the EPA has identified potential alternative compliance pathways for affected newly constructed, modified, and reconstructed fossil fuel - fired steam generating units. We are finalizing an emission standard for newly constructed highly efficient fossil fuel
fired steam generating units that can be met by capturing and storing approximately 16 to 23 percent of the CO 2 produced from the facility or by utilizing other technologies such as natural***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **662** of **763** gas co - firing . For a subcategory of steam generating units that conduct “large” modifications according to definitions in this final rule, we are finalizing an emission standard that is based
on a unit
- specific emission limitation consistent with each modified unit’s best one
- year historical performance and can be met through a combination of best operating practices and equipment upgrades. For reconstructed steam generating units, the EPA is finalizing standards of performance based on the performance of the most efficient generation technology available, whi ch we concluded is the use of the best available subcritical steam conditions for small units and the use of supercritical steam conditions for large units. The standards can also be met through other technology options such as natural gas co - firing. In li ght of these potential alternative compliance pathways, we believe that sources will have ample opportunity to coordinate their response to this rule with any obligations that may be applicable to affected EGUs as a result of the MATS, CSAPR, 316(b), SE ELG and CCR rules, all of which are or soon will be final rules

— and to do so in a manner that will help reduce cost and ensure reliability, while also ensuring that all applicable environmental requirements are met . 579

579 It should be noted that regulatory obligations imposed upon***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **663** of **763** The EPA is also endeavoring to enable E GUs to comply with applicable obligations under other power sector rules as efficiently as possible (e.g., by facilitating their ability to coordinate planning and investment decisions with respect to those rules) and, where possible, implement integrated compliance strategies. Section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with this rule describes such an example with respect to the SE ELG and CCR rules . In light of the compliance flexibilities we are offering in this action, we believe that sources will have ample 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 assuring an adequate, affordable, and reliable supply of electricity. **XII I**  **. Impacts of this Action** As explained in the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EPA
- 452/R
- 15
- 005 , August 2015) (RIA), states and sources operate independently under different statutes and sections of statutes; the EPA expects that states and sources will take advantage of available flexibilities as appropriate, but will comply with all relevant legal requirements.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **664** of **763**
ava ilable data indicate that, even in the absence of the standards of performance for newly constructed EGUs, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that will meet the standards without installation of additional controls. Therefore, based on the analysis presented in Chapter 4 of the RIA, the EPA projects that this final rule will result in negligible CO 2 emission changes, quantified benefits, and costs on owners and operators of newly constructed EGUs by 2022. 580 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 newly constructed EGUs will result in negligible cos ts and benefits, the EPA has also performed several illustrative analyses that show the potential impacts of the rule if certain key assumptions were to change. This includes an analysis of the impacts under a range of natural gas prices and the costs and benefits associated with building an illustrative coal
- fired EGU with CCS. These are presented in Chapter 5 of the RIA. As also explained in the RIA for this final rule, the EPA also expects that few sources will trigger either the NSPS modification or rec onstruction provisions that we are finalizing
580 Conditions in the analysis year of 2022 are represented by a model year of 2020.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **665** of **763** today. 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. A. What are the air impacts? As explained immediately above, the EPA does not anticipate 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 EGUs will likely choose technologi es, primarily NGCC, which meet the standards even in the absence of this rule due to existing economic conditions as normal business practice. As also explained immediately above, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. New steam generating EGUs that choose to comply with the final standard of performance by implementing partial post
combustion CCS are likely to use commercially
- available amine
based capture systems. Some concern has been raised regarding emissions of amines and amine degradation of amines (e.g. , ammonia, NH3) for the capture process. To reduce the amine emissions, MHI introduced the first optimized washing system within an absorber column in 1994, and developed a proprietary washing system in 2003. In that system, a proprietary reagent is added to the water washing section to capture amine impurities***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **666** of **763** such as amine, degraded amine, ammonia, formaldehyde, acetaldehyde, carbonic acids and nitrosamines. 581 MHI has continued to improve this technology for further reduction of amine emissions and establi shed an “advanced amine emission reduction system”. Research performed by MHI at Alabama Power’s Plant Barry indicated that an increasing SO 3 content in flue gas caused a significant increase of amine emissions. During testing, at Plant Barry MHI applied i ts proprietary washing system and confirmed that the amine emission were drastically reduced. 582 Others have also studied emissions and control strategies and have determined that a conventional multi
- stage water wash and mist eliminator at the exit of the CO 2 scrubber is effective at removal of gaseous amine and amine degradation products emissions. 583 , 584 Additional research continues in this area. B. Endangered Species Act

581 Sharma, S.; Azzi, M.; “A critical review of existing strategies for emission control in the monoethanolamine
-based carbon capture process and some recommendations for improved strategies”, Fuel , 121, 178 (2014). 582 Kamijo, T.; et al., “SO 3 Impact on Amine Emission and Emission Reduction Technology”, Energy Procedia , Volume 37, 1793 (2013). 583 Sharma, S. (2014). 584 Mertens, J.; et al., “Understanding ethanolamine (MEA) and ammonia emissions from amine based post combustion carbon capture: Lessons learned from field tests”, Int’l J. of GHG Control , 13, 72 (2013).***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **667** of **763** Consistent with the requirements of section 7(a)(2) of the Endangered Species Act (ESA), the EPA has also considered the effects of this rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed endangered or threatened species
or the designated critical habitat of such species and whether consultation with the U.S. Fish and Wildlife Service (FWS) and/or National Marine Fisheries Service (together, the Services) is required by the ESA . Section 7(a)(2) of the ESA requires federal agencies, in consultation with the Service(s), to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of federally listed endangered or threatened species o r result in the destruction or adverse modification of designated critical habitat of such species. 16 U.S.C. 1536 (a)(2). Under relevant implementing regulations, ESA section 7(a)(2) applies only to actions where there is discretionary federal involvement or control. 50 CFR 402.03 . Furthe r, under the regulations consultation is required only for actions that “may affect” listed species or designated critical habitat. 50 CFR 402.14. Consultation is not required where the action has no effect on such species or habitat. Under this 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***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **668** of **763** the direct and indirect effects that will be added to the environmental baseline. 50 CFR 402.02 . Direct effects are the direct or immediate effects of an action on a listed species or its habitat. 585 Indirect effects are those that are “ caused by the proposed action and are later in time, but still 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 listed species, and if the effect is indirect, it must be reasonably certain to
occur. The EPA notes that the p rojected environmental effects of this final action are positive: reductions in overall GHG emissions, and reductions in PM and ozone
-precursor emissions (SOX and NOX ). However, the EPA’s assessment that the rule will have an overall net positive environmental effect by virtue of reducing emissions of certain air pollutants does not address whether the rule may affect any listed species or designated critical habitat for ESA section 7(a)(2) purposes and does not constitute any finding of effects for that pu rpose. The fact that the rule will have overall positive effects on the national
585 See Endangered Species Consultation Handbook, U.S. Fish & Wildlife Service and National Marine Fisheries Service at 4
- 25 (March 1998) (providing examples of direct effects: e.g. , driving an off road vehicle through the nesting habitat 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
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– Do Not Cite, Quote or Release During Review *** Page **669** of **763** and global environment 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 se ction 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 XII I .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 fuel
fired steam generating units to be built. Emissions reductions from turbines are likewise projected to be minimal. Moreover, we reasonably project that capacity additions during the analysis period out to 2022 would already be compliant with the rule’s requirements (e.g., natural gas combined cycle units, low capacity factor natural gas combustion turbines, and small amounts of coal - fired units with CCS supported by Federal and State funding). See RIA chapter 4. With respect to the projected GHG emission reductions, the EPA does not believe that such minor reductions trigger ESA consultation requirements under section 7(a)(2). In reaching this conclusion, the EPA is mindful of significant legal and technical analysis undertaken by FWS and the U.S. Department of the Interior (DOI) in the context of listing the polar bear as a threatened species under the ESA. In that context, in 2008, FWS***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **670** of **763** and DOI expressed the view that the best sci entific data available were insufficient to draw a causal connection between GHG emissions and effects on the species in its habitat. 586 The DOI Solicitor concluded that where the effect at issue is climate change, proposed actions involving GHG emissions cannot pass the “may affect” test of the section 7 regulations and thus are not subject to ESA consultation. The EPA has also previously considered issues relating to GHG emissions in connection with the requirements of ESA section 7(a)(2) and has supplemented DOI’s analysis with additional consideration of GHG modeling tools and data regarding listed species. The EPA evaluated this same issue in the context 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 the lifetimes of the model years in question 587 and, based on air quality modeling of potential environmental effects, concluded that “EPA knows of no modeling tool which can link these small, time
-
586 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).

587 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
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– Do Not Cite, Quote or Release During Review *** Page **671** of **763** attenuated changes in global metrics to particular effects on listed species in particular areas. Extrapolating from global metric to local effect with such small numbers, and accounting for further links in a causative chain, remain beyond current modeling capabilities.” EPA, Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel Economy Standards, Response to Comment Document for Joint Rulemaking at 4
- 102 (Docket EPA
OAR- HQ - 2009
- 4782). The EPA reached this conclusion afte r evaluating issues relating to potential improvements relevant to both temperature and oceanographic pH outputs. The EPA's ultimate finding was that “any potential for a specific impact on listed species in their habitats associated with these very small changes in average global temperature and ocean pH is too remote to trigger the threshold for ESA section 7 (a)(2).” Id. The EPA believes that the same conclusions apply to the present action, given that the projected CO 2 emission reductions are far less than those projected for either of the light duty vehicle rules. See, e.g., Ground Zero Center for Non - Violent Action v. U.S. Dept. of Navy, 383 F. 3d 1082, 1091
- 92 (9th Cir. 2004) (where the likelihood of jeopardy to a species from a federal action is extremely remote, ESA does not require consultation). The EPA’s conclusion is entirely consistent with DOI’s analysis***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **672** of **763** regarding ESA requirements in the context of federal actions involving GHG emissions. 588 The EPA received a comment on the proposal referencing a prior letter sent to EPA by three U.S. Senators, 589 which asserted that the rule will cause a shift to alternative sources of energy such as wind and solar and that such facilities may have impacts on listed species. The comment inquired regarding ESA consultation in connection with the rule. We reiterate that no consultation is required for a rule without potential for a specific impact on listed species in their habitats.

588 The EPA has received correspondence from a U.S. Senator and a Member of the U.S. House of Representatives noting that the Services have identified several listed species affected by global climate change. See Letter from Rob Bishop, Chairman, House Committee on Natural Resources, to Gina McCarthy, Administrator, U.S. Environmental Protection Agency, dated June 1 1 , 2015 ; Letter from Rob Bishop, Chairman, House Committee on Natural Resources, and James M. Inhofe, Chairman, Senate Committee on Environment and Public Works, to Gina McCarthy, Administrator, U.S. Environmental Protection Agency, dated June 15, 2015. EPA’s asses sment of ESA requirements in connection with the present rule does not address whether global climate change may, as a general matter, be a relevant consideration in the status of certain listed species. Rather, the requirements of ESA section 7(a)(2) must be considered and applied to the specific action at issue. As explained above, EPA’s conclusion that ESA section 7(a)(2) consultation is not required here is premised on the specific facts and circumstances of the present rule and is fully consistent with prior relevant analyses conducted by DOI, FWS, and EPA. 589 See Letter from David Vitter, James M. Inhofe, and Mike Crapo, United States Senate Committee on Environment and Public Works, to Gina McCarthy, Administrator, U.S. Environmental Protection Agency , and Dan Ashe, Director, U.S. Fish and Wildlife Service, dated March 6, 2014.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **673** of **763** C. What are the energy impacts? This final rule is not anticipated to have a notable effect on the supply, distribution, or use of energy. As previously stated, the EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily NGCC units, because of existing and expected market conditions. As also previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis . D. What are the water and solid waste impacts? This final ru le 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 build new EGUs that comply with the regulatory requirements of this rule even in its absence , primarily through the construction of new NGCC units . As also previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Still there are expected to be a small number of coal plant s with CCS and the use of CCS systems (especially post
- combustion system) will increase the amount of water used at the facility. If those plant s utilize partial CCS to meet the final standard of performance (i.e., approximately 16 to 23 percent capture), the increased water use will not be***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **674** of **763** significant. See section V.O.2. The EPA is unaware of any solid waste impact resulting from this rule. 590 E. What are the compliance costs? For steam generating EGUs, the EPA has carefully analyzed the costs of meeting the promulgated standard of performance for a highly efficient SCPC using partial CCS and found these costs to be reasonable. See sections V.H and I above. This analysis assumes new capacity not otherwise compliant with the standards would be constructed. Bas ed on the analysis in chapter 4 of the RIA, the EPA believes the standards of performance for newly constructed EGUs will have no notable compliance costs, because electric power companies are expected to build new EGUs that comply with the regulatory requ irements of this final rule even in the absence of the rule, primarily NGCC units, due 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 benefits due to existing generation choices, the EPA recognizes that some companies may choose to construct coal or other fossil fuel
fired units and has set standards for these units accordingly.

590 Estimated costs for the rule inc lude costs for fly ash and bottom ash disposal and for spent solvent recovery and handling. See “Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3”, DOE/ NETL - 2015 /1723 (July 2 015) at pp. 43, 130.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **675** of **763** For this reason, the RIA also analyzes project
- level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel
- fired unit with CCS. This analysis indicates that the quantifiable health and climate benefits of the standard exceed regulatory costs under a range of assumptions . In addition, the EPA believes the standards of performance for modified and reconstructed EGUs will have minimal associated compliance costs, because, as previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. F. What are the economic and employment impacts? The EPA does not anticipate that this final rule will result in notable CO 2 emission changes, energy impacts, monetized benefits, costs, or economic impacts by 2022 as a result of the standards of performance for newly constructed EGUs. The owners of newly constructed EGUs will likely choose technologies that meet the standards even in the absence of this rule, due to existing economic conditions as normal business practice. Likewise, the EPA believes this rule will not have any impacts on the price of electricity, employment or labor markets, or the U.S. economy. See RIA chapter 4 .6. 591

591 The employment analysis in this RIA is part of EPA’s ongoing effort to “conduct continuing evaluations of potential loss or***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **676** of **763** As previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstruction provisions. As with the new source standards, the EPA does not expect macroeconomic or employment impacts as a result of the standards. G. What are the benefits of the final standards ? We are not projecting direct monetized climate benefits in terms of CO 2 emission reductions associated with these standards of performance. This is because, as stated above, the EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily NGCC units, because of existing and expected market conditions. See RIA chapter 4. Chapter 5 of the RIA contains analysis documenting that if new coal capacity is added, there are net quantified benefits, 592 in the form of both CO 2 reductions and reductions in emissions of criteria pollutants controlled incidentally by the standard. Moreover, a cost - reasonable standard is, in fact, what will drive new technology deployment and provide a path forward for new coal
fired capacity. See section V. L above.
shifts of employment which may result from the administration or enforcement of [the Act]” pursuant to CAA se ction 321(a). 592 These benefits are projected to exceed regulatory costs under a range of assumptions .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **677** of **763** As also previously stated, the EPA anticipates few units will trigger the NSPS modification or reconstruction provisions. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. **XI V**  **. Statutory and Executive Order Reviews** Additional information about these Statutory and Execut ive Orders can be found at http://www2.epa.gov/laws
regulations/laws
- and- executive
- orders. A. Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review This final action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. It is a significant regulatory action because it raises novel legal or policy issues arising out of legal mandates. Any changes made in response to OMB recommendations have been documented in the established dockets for this action under Docket ID No. EPA- HQ - OAR- 2013
- 0495 ( Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. EPA- HQ - OAR- 2013
- 0603 ( Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units) . The EPA prepared an economic analysis of the potential costs and***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **678** of **763** benefits associated with this action. Thi s analysis, which is contained in the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” ( EPA- 452/R
- 15
- 005, Augus t 2015 ), is available in both dockets. The EPA does not anticipate that this final action will result in any notable compliance costs. Specifically, we believe that the standards for newly constructed fossil fuel
- fired EGUs (electric utility steam generating units and natural gas
- fired stationary combustion turbines) will have negligible costs associated with it over a range of likely sensitivity conditions because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this action even in the absence of the action, because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal
- fired steam generating units without CCS to be bu ilt in the absence of this action. However, because some companies may choose to construct coal or other fossil fuel
- fired EGUs, the RIA also analyzes project
- level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel
- fire d EGU with CCS. As noted above, this analysis indicates that quantifiable benefits exceed compliance costs under a range of assumptions .***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **679** of **763** The EPA also believes that the standards for modified and reconstructed fossil fuel
- fired EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis (through 2022). 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. B. Paperwork Reduction Act (PRA) The information co llection 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 submi tted to OMB for the proposed standards for newly constructed EGUs (EPA ICR number 2465.02) and the proposed standards for modified and reconstructed EGUs (EPA ICR number 2506.0 1 ). 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 TTTT) and are being finalized in the same action, the ICR document for this action includes estimates of the information co llection burden on owners and operators of newly constructed, modified, and reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics (BLS) labor cost data. Thus, all***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **680** of **763** burden estimates are in 2013 dollars. Burden is defined at 5 CFR 1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbers EPA
- HQ - OAR- 2013
- 0495 and EPA
- HQ OAR- 2013
- 0603), and it is briefly summarized here. The information collection requirements are not enforceable until OMB approve s them. The recordkeeping and reporting requirements in this final action are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency 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 listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to disp lay the OMB control number for the approved information collection activities contained in this final action. 1. Newly Constructed EGUs This final action will impose minimal new information collection burden on owners and operators of affected newly***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **681** of **763** constructed fossil fuel
- fired EGUs (steam generating units and stationary combustion turbines) beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under 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 costs to comply with the emission standards under the rule , there are no new information collection costs, as the information required by the standards for newly constructed EGUs is already collected and reported by other regulatory programs . The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements 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 newly constructed NGCC units and 25 affected newly constructed natural gas - fired simple c ycle combustion turbines will commence operation during that time period. As a result of this final action, owners or operators of those newly constructed units***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **682** of **763** 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 information collection burden under the provisions of the PRA on owners and operators of affected modified and reconstructed fossil fuel
fired EGUs (steam generating units and stationary combustion turbines) . As previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel
- fired electric utility steam generating units or stationary combustion turbines will take actions that would constitute modifications or reconstructions as defined under the EPA’s NSPS regulations. Accordingly, the standards for modified and reconstructed EGUs a re not anticipated to impose any information collection burden over the 3
- year period covered by this ICR. We have estimated, however, the information collection burden that would be imposed 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 collection burden on those affected EGUs beyond what they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As desc ribed above, the OMB has previously approved***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **683** of **763** the information collection requirements contained in the existing part 75 and 98 regulations. Apart from certain reporting costs to comply with the emission standards under the rule , there would be no new information collection costs, as the information required by the final rule is already collected and reported by other regulatory programs. As stated above, although the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions, if an EGU were to modify or reconstruct during the 3
- year period covered by this ICR , the owner or operator 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 costs or O&M costs associated with burden for modified or reconstructed EGUs. 3. Information Collection Burden The annual information collection burden for newly constructed, modified, and reconstructed EGUs consists only of reporting burden as explained above. The annual reporting burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated t o be $ 60,97 7 and 651 labor hours. There are no annualized capital costs or O&M costs associated with burden for newly constructed , modified, or reconstructed EGUs. Average burden hours per response are***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **684** of **763** estimated to be 7 hours. The total number of respondents 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 determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has 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 will choose to build new fossil fuel
- 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. RIA Chapter 4. The EPA does not project any new coal
- fired steam generating units without CCS t o be built. We expect that any newly constructed natural gas - fired stationary combustion turbines will meet the standards. We do not include an analysis of the illustrative impacts on small entities that may result from implementation of the final rule bec ause we anticipate***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **685** of **763** negligible compliance costs over a range of likely sensitivity conditions as a result of the standards for newly constructed EGUs. Thus the cost - to - sales ratios for any affected small entity would be zero costs as compared to annual sale s revenue for the entity. Accordingly, there are no anticipated economic impacts as a result of the standards for newly constructed EGUs. (See the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” ( EPA- 452/R
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- 005, August 2015 ) for further discussion of sensitivities.) We have therefore concluded that this final action will have no net regulatory burden for all directly regulated small entities. 2. Modified and Reconstructed EGUs The EPA expects few fossil fuel
- fired electric utility steam generating units to trigger the NSPS modification provisions in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the source’s maximum achievable hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take actions that would constitute modifications as defined under the EPA’s NSPS regulations. In addition, the EPA expects few reconstructed fossil fuel
fired electric utility steam generating units or natural gas
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– Do Not Cite, Quote or Release During Review *** Page **686** of **763** fired stationary combustion turbines in the period of analysis. Reconstructi on occurs when a single project replaces components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility. 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 anticipate that the rule would impose significant costs on those sources, including any that are owned by small entities. (See the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” ( EPA- 452/R
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- 005, August 2015 ) . D. Unfunded Mandates Reform Act (UMRA) This final action does not contain an unfunded mandate 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 constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel
fired electric utility steam generating units or natural gas
fired stat ionary combustion turbines that comply with the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **687** of **763** regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any new coal - fired steam generating units without CCS to be built and expects that any newly constructed natural gas - fired stationary combustion turbines will meet the standards. (See the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” ( EPA452/R
- 15
- 005, August 2015 ) for further discussion of sensitivities.) As previously stated, 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 the period of analysis. 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 anticipate that the rule would impose significant costs on those sources. (See the “Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electri c Utility Generating Units” ( EPA- 452/R
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- 005, August 2015 ).) We have therefore concluded that the standards for newly constructed, modified, and reconstructed EGUs do not impose***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **688** of **763** enforceable duties on any state, local or tribal governments, 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 regulatory requirements that might significantly or uniquely affect small governments. The threshold amount established for determining 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 result in expenditures of $100 million or more in any one year. Specifically, the EPA does not project any new coal
- fired steam generating units without CCS to be built and expects that any newly constructed natural gas - fired s tationary combustion 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 the period of analysis. E. Executive Order 13132, Federalism This final action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **689** of **763** various l evels of government. The EPA believes that electric power companies will choose to build new fossil fuel
- fired electric utility steam generating units or natural gas
- fired stationary combustion turbines that comply with the regulatory requirements of the f inal 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 gas
- fired stationary combustion turbines to trigger the NSPS modificat ion or reconstruction provisions in the period of analysis. We, therefore, anticipate that the final rule will impose minimal compliance costs. F. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments This final action does no t have tribal implications as specified in Executive Order 13175 . The final rule will impose requirements on owners and operators of newly constructed, 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 combustion turbines, located in Indian Country, but is not aware 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 existing EGUs such as those located at the four facilities in Indian Country***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **690** of **763** only if those EGUs were to take actions constituting modifications or reconstructions as defined under the EPA’s NSPS regulation s . As previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Thus, the rule will neither impose substantial direct compliance costs on tribal governments nor preempt Tribal law. Accordingly, Executive Order 13175 does not apply to this action. Nevertheless, because the EPA is aware of Tribal interest 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 with tribal officials during development of this rule. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consultation letters to the leaders of all federally recognized tribes. Although only newly constru cted, modified, and reconstructed EGUs will be affected by this action, the EPA’s consultation regarded planned actions for new and existing sources. The letters provided information regarding the EPA’s development of NSPS and emission guidelines for EGUs and offered consultation. 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 Lake Band of Ojibwe. A description of that consultati on is included in the***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **691** of **763** 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 action for newly constructed EGUs was signed on Sept ember, 20, 2013. On November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding the EPA’s development of carbon pollution standards for new, modified, reconstructed and existing EGUs and offered consultation. No tribes requested consultation 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 to proposal of GHG standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011, with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA also held a series of listening sessions prior to proposal of GHG standards for modified and reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a session on September 9, 2013, together with the state agencies, as well as in a separate tribe
- only session on September 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 environmental***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **692** of **763** staff with the National Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outreach is included in the preamble to the proposed emission guidelines for existing EGUs (79 FR 34830, June 18, 2014). G. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866. While the action is not subject to Executive Order 13045, the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect 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 constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel - fired electric utility steam generating units or natural gas - fired stationary combustion turbines that comply with the regulatory requirements of the rule because of existing and***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **693** of **763** expected market conditions The EPA believes that the CO 2 emission reductions resulting from implementation of these final standards, as well as substantial ozone and PM2.5 emission reductions as a co
-benefit, will further improve chi ldren’s health. However, the RIA also analyzes project
- level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel
- fired unit with CCS. RIA chapter 5. Under these scenarios, the rule would result in substantial reductions o f both CO 2 , and also fine particulate matter (sulfate PM 2.5) such that net quantifiable benefits exceed regulatory costs under a range of assumptions . Under these same scenarios, this rule would have a positive effect for children’s health. The assessment literature cited in the EPA’s 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the 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. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **694** of **763** from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availabil ity and increases prices, leading to food insecurity within households. More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of this preamble. H. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This final action is not a “significant energy action” because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. See section V.O.3 above. The EPA believes that electric power companies will choose to build new fossil fuel
- fired electric 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 stated, 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 reconst ruction provisions in the period of***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **695** of **763** analysis. Thus, this action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry. I. National Technology Transfer and Advancement Act (NTTA) and 1 CFR part 51 This final action involves technical standards. The following voluntary consensus standards are used in the final rule: American Society for Testing and Materials (ASTM) Methods D388
- 12 (Standard Classification of Coals by Rank), D396
- 13c (Standard Specifi cation for Fuel Oils), D975
- 14 (Standard Specification for Diesel Fuel Oils), D3699
- 13b (Standard Specification for Kerosene), D6751
- 12 (Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels), D7467
- 13 (Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 (American National Standard for Electricity Meters
- 0.2 and 0.5 Accuracy Classes). The rule also requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain standards that have already been reviewed under the NTTAA. J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low
- Income Populations***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **696** of **763** Executive Order 128 98 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by i dentifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies , and activities on minority populations and low
- income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal 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 to the decision
-making process to have a healthy environment in which to live, learn, and work. Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endange rment Finding. As part of the Endangerment Finding, the Administrator considered climate change risks to minority or low- income populations, finding that certain parts of the population may be especially vulnerable based on their***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **697** of **763** circumstances. Populations that were found to be particularly vulnerable to climate change risks include the poor, the elderly, the very young, those already in poor health, the disabled, those living alone, and/or indigenous populations dependent on one or a few resources. See Sec tions F and G, above, where EPA discusses Consultation and Coordination with Tribal Governments and Protection of Children. The Administrator placed weight on the fact that certain groups, including children, the elderly, and the poor, are most vulnerable to climate
- related health effects. The record for the 2009 Endangerment Finding summarizes the strong scientific evidence in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies that the potential impacts of climate change raise environmental justice issues. These reports concluded that poor communities can be especially vulnerable to climate change impacts bec ause they tend to have more limited adaptive capacities and are more dependent on climate
- sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particula rly those impacted by degradation of natural and cultural resources within established reservation boundaries and threats to***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **698** of **763** traditional subsistence lifestyles. Tribal communities whose health, economic well
-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. The 2009 Endangerment Finding record also specifically noted that Southwest native cultures are especially vulnerable to water qua lity and availability impacts. Native Alaskan communities are already experiencing disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well
-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low- income populations in the United States. 593 The new

593 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp. IPCC, 2014: Climate Change 2014: Impacts, Adaptation , and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, 1132 pp. IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects . Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **699** of **763** assessment literature provides more detailed findings regarding these populations’ vulnerabilities and projected impacts they may experience. In addition, the most recent assessment reports provides new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These reports find that cert ain climate change related impacts

—including heat waves, degraded air quality, and extreme weather events

—have disproportionate effects on low
income and some communities of color, raising environmental justice concerns. Existing health disparities and other inequities in these communities increase their vulnerability to the health effects of climate change. In addition, assessment reports also find that climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United States. As the scientific literature presented above and in the Endangerment Finding illustrates, low income communities and
some communities of color are especially vulnerable to the health and other adverse impacts of climate change.

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, 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, 688 pp.***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **700** of **763** The EPA believes the human health or environmental risk addressed by this final action will not have potential disproportionately high and adverse human health or environmental effects on minority, low
- income or indigenous populations. The final rule limits GHG emissions from newly constructed, modified, and reconstructed fossil fuel
- fired electric utility steam generating units and natural gas
- fired stationary combustion turbines by establishing national emission standards 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 indigenous populations because the rule is not anticipated to notably affect the level of pro tection provided to human health or the environment. The EPA believes that electric power companies will choose to build new fossil fuel
- fired electric utility steam generating units and natural gas
- fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal
- fired steam generating units without CCS to be built and expects that any newly built natural gas - fired stationary combusti on turbines will meet the standards. In addition, as previously stated, the EPA expects few fossil fuel
- fired electric utility steam generating units or***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **701** of **763** natural gas - fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. This final rule will ensure that, to whatever extent there are newly constructed, modified, and reconstructed EGUs, they will use the best performing technologies to limit emissions of CO 2 . K. Congressional Review Act (CRA) This final action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a “major rule” as defined by 5 U.S.C. 804(2). **XV. Withdrawal of Proposed**  **Standards for Certain Modified Sources**  In this action , as discussed above in sections IV and VI, the EPA is issuing final standards of performance for affected fossil fuel
- fired steam generating EGUs that implement modifications resulting in an increase of CO 2 emissions (in lb/hr) of more than 10 percent. In addition, the EPA is withdrawing the proposed standards of performance for 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 resulting in an increase of CO 2 emissions (in lb/hr) of less than or equal to 10***EO 12866_Review
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– Do Not Cite, Quote or Release During Review *** Page **702** of **763** 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 proposed standards for modified stationary combustion turbines. A detailed rationale for the withdrawal of these proposed standards is provided in section IX above. The proposed standards for modified fossil fuel
- fired EGUs that the EPA is withdrawing in this action were published in the **Federal Register** on June 18, 2014 (79 FR 34960). **X V** **I .**  **Statutory Authority** The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).*** E.O. 12866 Review
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– Do Not Cite, Quote or Release During Review *** **Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility**  **Generating Units** Page **703** of **763 List of Subjects**  40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. 40 CFR Part 70 Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements. 40 CFR Part 71 Environmental protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements. 40 CFR Part 98 Environmental protection, Greenhouse gases and monitoring, Reporting and recordkeeping requirements. Dated: __________________.

________________________ Gina McCarthy, AdministratorPage **704** of **763** For the reasons stated in the preamble, title 40, chapter 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 STATIONARY SOURCES** 1. The authority citation for part 60 continues to read as follows: Authority: 42 U.S.C. 7401, et seq. 2. Part 60 is amended by adding subpart TTTT to read as follows: **Subpart TTTT Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units**  Sec. **Applicability** §60.5508 What is the purpose of this s ubpart? §60.5509 Am I subject to this subpart? **Emission Standards** §60.5515 Which pollutants are regulated by this subpart? §60.5520 What CO 2 emissions standard must I meet? **General Compliance Requirements** §60.5525 What are my general requirements for c omplying with

this subpart? **Monitoring and Compliance Determination Procedures** §60.5535 How do I monitor and collect data to demonstrate

compliance? §60.5540 How do I demonstrate compliance with my CO 2 emissions

standard and determine excess emissions? **Notifications, Reports, and Records**Page **705** of **7 63**  §60.5550 What notifications must I submit and when? §60.5555 What reports must I submit and when? §60.5560 What records must I maintain? §60.5565 In what form and how long must I keep my records? **Other Requirements and Information** §60.5570 What parts of the General Provisions apply to my affected EGU? §60.5575 Who implements and enforces this subpart? §60.5580 What definitions apply to this subpart? **Applicability §60.5508 What is the purpose of this subpart?**  This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences const ruction 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 combustion turbine that commenced construction after January 8, 2014 or commenced modification or reconstruction after June 18, 2014 that meetsPage **706** of **763** the relevant applicability conditions in paragraphs (a)(1) and (a)(2) of this section. (1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either alone o r in combination with any other fuel), and (2) Serves a generator capable of selling greater than 25 MW of electricity to a utility power distribution system. (b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (b)(8) of this section. (1) Your EGU is a steam generating unit or IGCC that is currently and always has been subject to a federally enforceable permit condition limiting annual net
- electric sales to no more than one - third of its potential electric output or 219,000 MWh, whichever is greater. (2) Your EGU is capable of combusting 50 percent or more
non - fossil fuel and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less. (3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting annual net - electric sales to no more than the product of the unit's net design efficiency and the unit's potential electric output or 219,000 MWh, whichever is greater.Page **707** of **763** (4) Your EGU serves a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity ( determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less. (5) Your EGU is a municipal waste combustor that is subject to subpart Eb of this part. (6) Your EGU is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part. (7) Your EGU is a steam generating unit(s) or IGCC that undergoes a modification resulting in an hourly increase in CO 2 emissions (mass per hour) of 10 percent or less (2 significant figures). Modified units that are not subject to the requirements of this subpart pursuant to this subsection continue to be existing units under section 111 with respect to CO2 emissions standards. (8) Your EGU is a stationary combustion turbine that is not capable of combusting natural gas (e.g., not connected to a natural gas pipeline). **Emission Standards §60.5515 Which pollutants are regulated by this subpart?**  (a) The pollutants regulated by this subpart are greenhouse gase s. The greenhouse gas standard in this subpart is in the form of a limitation on emission of carbon dioxide.Page **708** of **763** (b) PSD and Title V Thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR § 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Ac t as defined in § 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48) of this chapter. (2) For the purposes of 40 CFR § 52.21(b)(50)(ii), with respect to GHG emissions from affecte d facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter. (3) For the pu rposes of 40 CFR § 70.2 of this chapter, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "s ubject to regulation" as defined in 40 CFR § 70.2 of this chapter. (4) For the purposes of 40 CFR § 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated underPage **709** of **763** section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined i n 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) and (c) of this section, as applicable. (b) Except as specified in paragraph (c) of the section, you must comply with the applicable gross energy output standard and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross energy output standard. For the remainder of this subpart, where the term “gross or net energy output” is used, the term that applies to you is “gross energy output.” (c) As an alternate to meeting the requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, beginning on the date the Administrator grants the petition, the affected EGU must comply with the applicable net energy output based standard included in this subpart. Your operating permitPage **710** of **763** must include monitoring, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the remainder of this subpart, where the term “gross or net energy output” is used, the term that applies to you is “net energy output.” Owner s or operators complying with the net output based standard must petition the Administrator to switch back to complying with the gross energy output based standard. **General Compliance Requirements §60.5525 What are my general requirements for complying wit** **h this subpart?**  Compliance with the applicable CO 2 emission standard of this subpart shall be determined on a 12
- operating month rolling average basis. See Tables 1
- 2 for the applicable CO 2 emission standards. (a) You must be in compliance with the emissi on standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1). (1) For each affected EGU sub ject to a CO 2 emissions standard based on a 12
- operating month rolling average, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected EGU at the end of the initialPage **711** of **763** and each subsequent 12
- operating month period . (2) For each affected EGU subject to the CO 2 emissions standard for multi
- fuel units, you must determine the total heat input in million Btu’s (MMBtu) from natural gas (HTIP ng ) and the total heat input from all other fuels combined (HTIP o ) using one of the methods under §60.5535(d)(2). You must then use the following equation to determine the applicable emissions standard (EL) during the compliance period:

emission	standard = 120 x HTIP + (160 x HTIP ) Total	Heat	Input	from	All	Fuels Where: CO 2 emission standard = the emission standard during the

compliance period in units of lb/MMbtu. 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 than

natural gas that were f ired during the compliance period. 120 = allowable emission rate in lbs of CO2/MMBtu for heat

input derived from natural gas. 160 = allowable emission rate in lbs of CO2/MMBtu for heat

input derived from all fuels other than natural gas. (b) At all times you must operate and maintain eachPage **712** of **763** affected EGU, including associated equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart , and inspection of the EGU. (c) Within 30 days after the end of the initial compliance period (i.e., no more than 30 days after the first 12
- operating month compliance period), you must make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in Table 1 or Table 2 of this subpart, in accordance with the requirements in this subpart. The first operating month included in the initial 12
- operating month compliance period shall be determined as follows : (1) For an affected EGU that commences commercial operation (as defined in §72.2 of this chapter) on or after the effective date of this rule, the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) a fter the calendar month in which emissions reporting is required to begin under: (i) §63.5555(c)(3)(i), for units subject to the Acid RainPage **713** of **763** 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 commercial operation (as defined in §72.2 of this chapter) prior to the effective date of this rule: (i) If the date on which emissions reporting is required to begin under §75.64(a) of this chapter has passed prior to the effective date of this rule, emissions reporting shall begin according to §63.5555(c)(3)(i) (for Acid Rain program units), or according to §63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain Program). The first month of the initial compliance period shal l be the first operating month (as defined in §60.5580) after the calendar month in which the rule becomes effective; or (ii) If the date on which emissions reporting is required to begin under §75.64(a) of this chapter occurs on or after the effective dat e of this rule, then the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under §63.5555(c)(3)(ii)(A). (3) For a modified or reconstructed EGU that becomes subject to this subpart, the first month of the initial compliance period shall be the first operating month (as definedPage **714** of **763** in §60.5580) after the calendar month in which emissions 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 demonstrate**  **compliance?** (a) You must prepare a monitoring plan to quantify the hourly CO 2 mass emission rate (tons/hr), in accordance with the applicable provisions in §75.53(g) and (h) of this chapter. The electronic portion of the monitoring plan must be submitted using the ECMPS Client Tool and must be in place prior to reporting emissions data and/or the results of monitoring system certification tests under this subpart. The monitoring plan must be updated as necessary. Monitoring plan submittals must be made by the Designated Representative (DR), the Alternate DR, or a delegated agent of the DR (see §60.5555(c)). (b) You must determine the hourly CO 2 mass emissions in kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1) through (5) of this section, or, if applicable, as provided in paragraph (c) of this section. (1) Fo r an affected coal - fired EGU or for an IGCC unit you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record hourly average CO 2 concentrations in the affected EGU exhaust gasesPage **715** of **763** emitted to the atmosphere, and a flow monitoring system to measure hourly average stack gas flow rates, according to §75.10(a)(3)(i) of this chapter. As an alternative to direct measurement of CO 2 concentration, provided that your EGU does not use carbon separation (e.g., carbon capture and storage), 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 me asure CO 2 concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to §75.11(b) of this chapter. Alternatively, you may either use an appropriate fuel
- specific default moisture value from §75.11(b) or submit a petition to the Administrator under §75.66 of this chapter for a site
specific default moisture value. (2) For each continuous monitoring system that you use to determine the 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 chapter. (3) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions rate from the affected EGU; you must not apply the bias adjustment factors described in Section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data.Page **716** of **763** (4) You must select an appropriate reference method to setup (characterize) the flow mon itor and to perform the on
going RATAs, in accordance with part 75 of this chapter. If you use a Type - S pitot tube or a pitot tube assembly for the flow RATAs, you must calibrate the pitot tube or pitot tube assembly; you may not use the 0.84 default Type
- S pitot tube coefficient specified in Method 2. (5) Calculate the hourly CO 2 mass emissions (kg) as described in paragraphs (a)(6)(i) through (iv) of this section. Perform this calculation only for “valid operating hours”, as defined in §60.5540(a)(1). (i) Begin with the hourly CO 2 mass emission rate (tons/hr), 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 Appendix 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 defined in §72.2 of this chapter), to convert it to tons of CO 2. (iii) Finally, mul tiply the result from paragraph (b)(5)(ii) of this section by 909.1 to convert it from tons of CO 2 to kg. Round off to the nearest kg. (iv) The hourly CO 2 tons/hr values and EGU (or stack)Page **717** of **763** operating times used to calculate CO 2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6). You must use these data to calculate the hourly CO 2 mass emissions. (c) If your affected EGU exclusively combusts liquid fuel and/or gaseous fuel as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO 2 mass emissions according to paragraphs (c)(1) through (4) of this section. (1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) For each measured hourly heat input rate, use Equation G- 4 in Appendix G to part 75 of this chapter to calculate the hourly CO 2 mass emission rate (tons/hr). You may determine site
specific carbon
-based F - factors (F c ) using Equation F
- 7b in section 3.3.6 of appendix F to part 75 of this chapter, and you may use thes e F c values in the emissions calculations instead of using the default F c values in the Equation G
- 4 nomenclature. (3) For each “valid operating hour” (as defined in §60.5540(a)(1), multiply the hourly tons/h CO 2 mass emission rate from paragraph (c)(2) of this section by the EGU or stackPage **718** of **763** operating time in hours (as defined in §72.2 of this 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 of f 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. (d) Consistent with §60.5520, you must determine the basis of the emissions standard that applies to your affected source in accordance with either paragraph (d)(1) or (d)(2), as app licable: (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 install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly gross electric output or net electric output, as applicable, from the affected EGU(s). These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified unde r ANSI Standards No. C12.20 (incorporated by reference, see 60.17) . For a combined heat and power (CHP) EGU, as defined in §60.5580, you must also install, calibrate, maintain, andPage **719** of **763** operate meters to continuously (i.e., hour
-by-hour) determine and record the total useful thermal output. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record the hourly steam flow rate, temperature, and pressure. Your plan shall ensure that you ins tall, calibrate, maintain, and operate meters to record each component of the determination, hour
-by-hour. (2) If you operate a source subject to an emissions standard established on a heat
- input basis (e.g., lbs of CO2 per MMBtu of heat input), you must determine the total heat input for each fuel fired during the compliance period in accordance with one of the following procedures: (i) Appendix D to Part 75; (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). (e) Consistent with §60.5520, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly gross or net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. Alternatively, if the EGUs are identical, you may apportion the combined hourly gross or net electrical load to the individual EGUs according to the fractionPage **720** of **763** of the total heat input contributed by each EGU. (f) In accordance with §60.13(g) and §60.5520, if two or more affected EGUs that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard in Table 1 or 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, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual affected EGUs and you must express the operating time as “stack operating hours” (as defined in §72.2 of this chapter). If you attain compliance with the applicable emis sions standard in §60.5520 at the common stack, each affected EGU sharing the stack is in compliance. (g) In accordance with §60.13(g) and §60.5520 if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “ stack operating time” (as defined in §72.2 of this chapter) at each stack or duct separately. In this case, you must determinePage **721** of **763** compliance with the applicable emissions standard in Table 1 or 2 of this subpart by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU . h) Heat rate determination and design efficiency for 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 Cycles (incorporated by reference, see §60.17). (4) ASME PTC 22 Gas Turbines (incorporated by reference, see §60.17). (5) ASME PTC 46 Overall Plant Performance (incorporated 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 acceptance tests. Part 2: Method B
- Wide range of accuracy for variousPage **722** of **763** types and sizes of turbines (in corporated by reference, see §60.17). **§60.5540 How do I demonstrate compliance with my CO 2**  **emissions standard?**  (a) In accordance with §60.5520, to demonstrate compliance with the applicable CO 2 emission standard in Table 1 or 2 of this subpart, for the initial and each subsequent 12
- operating month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through (a)(7) of this section to calculate the CO 2 mass emissi ons 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 and either the generating load data from §60.5535(d)(1) or the heat input data from §60.5535(d)(2) in the calculations. (1) Each compliance period shall include only “valid operating hours” in the compliance period, i.e., operating hours for which: (i) “Valid data” (as defined in §60.5580) are obtained for all of the parameters used to determine the hourly CO 2 mass emissions (kg) and, if a heat input based standard applies, all the parameters used to determine total heat input for the hour are also obtained; andPage **723** of **763** (ii) The corresponding hourly gross or net energy output value is also valid data ( Note : for hours with no useful output, zero is considered to be a valid value). (2) You must exclude operating hours in which: (i) The substitute data provisions of part 75 of this chapter are applied for any of the parameters used to determine the hourly CO 2 ma ss emissions or, if a heat input based standard applies, for any parameters used to determine the hourly heat input; or (ii) An exceedance of the full
- scale range of a continuous emission monitoring system occurs for any of the parameters used to determine the hourly 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. (3) For each compliance period, at least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section. (4) You must calculate the total 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 compliance period. (5) Sources subject to output based standards. For each valid operating hour of the compliance period that was used in paragraph (a)(4) of this section to calculate the total CO 2 massPage **724** of **763** 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, as appropriate for the type of affected EGU(s). For an operating hour 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 useful thermal output, you must still determine the gross or net energy output for that hour. In addition, for an operating hour in which a valid CO 2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross electrical, mechanical, or useful thermal output, you must us e that hour in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads, net electric output shall be counted as zero for this calculation. (i) Calculate P gross/net for your affected EGU using the following equation. All terms in the equation must be expressed in units of megawatt
-hours (MWh). To convert each hourly gross or net energy output ( Consistent with §60.5520) value reported under part 75 of this chapter to MWh, multiply by the corresponding EGU or stack operating time.Page **725** of **763**
/ = ( ) + ( ) + ( )

− ( )
− ( ) TDF + [ ( ) + ( ) + ( ) ] 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 mechanical energy to the affected EGU or auxiliary equipment in MWh. ( Pe) FW = Electric energy used to power boiler feedwater

pumps at steam generating units in MWh. Not applicable to stationary combustion turbines, IGCC EGUs, or EGUs complying with a net energy output based standard. (Pe) A = Electric energy used for any auxi liary loads inPage **726** of **763** MWh. Not applicable for determining P gross . (Pt) PS = Useful thermal output of steam (measured relative

to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh. (Pt) HR = Non steam useful thermal output (measured

relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. (Pt) IE = Useful thermal output (relative to SATP

conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh. TDF = Electric Transmission and Distribution Factor of

0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0Page **727** of **763** percent of the total gross or net energy output consists of useful thermal output on a 12
- operating month rolling average bas is, or 1.0 for all other affected EGUs.
(ii) If applicable to your affected EGU (for example, for combined heat and power), you must calculate (Pt) PS using the following equation: ( ) = ×
Where: Qm = Measured steam flow in kilograms (kg) (or pounds

(lb)) for the operating hour. H = Enthalpy of the steam at measured temperature and

pressure (relative to SATP conditions or the energy in the condensate return line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb). CF = Conversion factor of 3.6 x 10 9 J/MWh or 3.413 x 10 6

Btu/MWh.
(6) Calculation of annual basis for standard. Sources complying with energy output
-based standards must calculate the basis (i.e., denominator) of their actual annual emission ratePage **728** of **763** in accordance with paragraph (6)(i). Sources complying with heat input based standards must calculate the basis of their 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 ca lculate the total gross or net energy output for the affected EGU’s compliance period by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)(5) of this section for all of the valid operating hou rs in the applicable compliance period. (ii) If you are subject to a heat input based standard, you must calculate the total heat input for each fuel fired during the compliance period. The calculation of total heat input for each individual fuel must incl ude all valid operating hours and must also be consistent with any fuel
- specific procedures specified within your selected monitoring option under §60.5535(d)(2). (7) If you are subject to an output based standard, you must calculate the CO 2 mass emission s 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 output value calculated according to the procedures in paragraph (a)(6)(i) of this section. Round off the result to two significant figures.Page **729** of **763** 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 according to the procedures in paragraph (a)(6)(ii) of this section. Round off the result to two significant figures. (b) In accordance with §60.5520, to demonstrate compliance with the applicable 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 determined according to the procedures specified in paragraph (a)(1) through (7) of this section and must be less than or equal to the applicable CO 2 emissions standard in Table 1, Table 2, or the emissions standard calculated in accordance with §60.5525(a)(2) of this subpart. **Not ification, Reports, and Records**  **§60.5550 What notifications must I submit and when?** (a) You must prepare and submit the notifications specified in §60.7(a)(1) and (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 specified in §75.61 of this chapter, as applicable to your affected EGUs. **§60.5555 What reports must I submit and when?**Page **730** of **763** (a) You must prepare and submit reports according to paragraphs (a) through (d) of this s ection, as applicable. (1) For affected EGUs that are required by §60.5525 to conduct initial and on
- going compliance determinations on a 12
- operating month rolling average basis, you must submit electronic quarterly reports as follows. After you have
accumulated the first 12
- operating months for the affected EGU, you must submit a report for the calendar quarter that includes the twelfth operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subse quent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report you must include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last (twelfth) operating month in a 12
- operating 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 fi rst and twelfth operating months in each compliance period for which you performed a CO 2 mass emissions rate calculation. If there are no compliance periods that end in the quarter, you must include a statement to that effect ;Page **731** of **763** (ii) If one or more compliance periods end in the quarter you must identify each operating month in the calendar quarter where your EGU violated the applicable CO 2 emission standard; (iii) If one or more compliance periods end in the quarter and there are no violations for the affected EGU, you must include a statement indicating this in the report; (iv) The percentage of valid operating hours in each 12
- operating month compliance period described in paragraph (a)(1)(i) of this section (i.e., the total number of valid operating hours (as defined in §60.5540(a)(1)) in that period divided by the total number of operating hours in that period, multiplied by 100 percent); (v) Consistent with §60.5520, the CO 2 emissions standard (as identified in Table 1 or 2) with which your affect ed EGU must comply; and (vi) Consistent with §60.5520, an indication whether or not the hourly gross or net energy output (P gross/net ) values used in the compliance determinations are based solely upon gross electrical load. (3) In the final quarterly repo rt of each calendar year, you must include the following: (i) Consistent with §60.5520, gross energy output or net energy output sold to an electric grid, as applicable to the units of your emission standard, over the 4 quarters of thePage **732** of **763** calendar year; and ( ii) The potential electric output of the EGU. (b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division i n the Office of Atmospheric Programs of EPA. (c) (1) For affected EGUs under this subpart that are also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter. (2) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the complian ce demonstrations required under this subpart. (3) (i) For all newly
- constructed affected EGUs under this subpart that are also subject to the Acid Rain Program, you must begin submitting the quarterly electronic emissions reports described in paragraph (c)(1) of this section in accordance with §75.64(a), i.e., beginning with data recorded on and after the earlier of: (A) The date of provisional certification, as defined inPage **733** of **763** §75.20(a)(3) of this chapter; or (B) 180 days after the date on which the EGU commences commercial operation (as defined in §72.2 of this chapter). (ii) For newly
- constructed affected EGUs under this subpart that are not subject to the Acid Rain Program, you must begin submitting the quarterly electronic reports described in paragraph (c)(2) of this section, beginning with data recorded on and after: (A) The date on which reporting is required to begin under §75.64(a), if that date occurs on or after the effective date of this rule; or (B) The effective date of this rule, if the dat e on which reporting would ordinarily be required to begin under §75.64(a) has passed prior to the effective date of this rule. (iii) For reconstructed or modified units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net energy output data on that date. Otherwise, emissions data reporting shall be on a gross energy output basis until the date that the Client Tool is first able to receive and process net energy output data. (4) If any required monitoring system has not been provisionally certified by the applicable date on whichPage **734** of **763** emissions data reporting is required to begin under paragraph (c)(3) of this section, the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with §75.4(j) of this chapter, §75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operating hours in which CO 2 mass emission rates are calculated using maximum potential values are not “valid operating hours” (as defined in §60.5540(a)(1)), and shall not be u sed in the compliance determinations under §60.5540. (d) For affected EGUs subject to the Acid Rain Program, the reports required under paragraphs (a) and (c)(1) of this section shall be submitted by: (1) The person appointed as the Designated Representative (DR) under §72.20 of this chapter; or (2) The person appointed as the Alternate Designated Representative (ADR) under §72.22 of this chapter; or (3) A person (or persons) authorized by the DR or ADR under §72.26 of this chapter to make the required submissions. (e) For affected EGUs that are not subject to the Acid Rain Program, the owner or operator shall appoint a DR and (optional) an ADR to submit the reports required under paragraphs (a) and (c)(2) of this section. The DR and ADR must register with thePage **735** of **763** Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submissions to one or more persons. (f) If your affected EGU captures CO 2 to meet the applicable emission limit, you must report in accordance with the requirements of 40 CFR Part 98 Subpart PP and either: (1) Report in accordance with the requirements of 40 CFR Part 98 subpart RR, if injection occurs on
- site, or (2) Transfer the captured CO 2 to an EGU or facility that reports in accordance with the requirements of 40 CFR Part 98 subpart RR, if injection occurs off
- site. (3) Transfer the captured CO 2 to a facility that has received an innovative technology waiver from EPA pursuant to paragraph (g) of this section. (g) Any person may request the Admi nistrator to issue 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 must 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 unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether thePage **736** of **763** technology will increase emissions or other releases of any pollutant other than CO 2 , and permanence of the CO 2 storage. The Administrator may test the system itself, or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology’s effectiveness, safety, and ability to store captured CO 2 without release. The Administrator may grant conditional approval of a technology, the approval condit ioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of releases of CO 2 or other pollutants. The Administrator will provide notice to the public of any application under this provision, and provide public notice of any proposed action on a petition before the Administrator takes final action. **§60.5560 What records must I maintain?** (a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in §60.7 (b) and (f). (b) (1) For affected EGUs subject to the Acid Rain Program, you must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (2) For affected EGUs that are not subject to the Acid Rain Program, you must also follow the recordkeeping requirements andPage **737** of **763** maintain records as required under subpart F of part 75 of this chapter, to the extent that those records provide applicable data for the compliance determinati ons required under this subpart. Regardless of the prior sentence, at a minimum, the following records must be kept, as applicable to the types of continuous monitoring systems used to demonstrate compliance under this subpart: (i) Monitoring plan records under §75.53(g) and (h) of this chapter; (ii) Operating parameter records under §75.57(b)(1) through (b)(4) of this chapter; (iii) The records under §75.57(c)(2) of this chapter, for stack gas volumetric flow rate; (iv) The records under §75.57(c)(3) for continuous moisture monitoring systems; (v) The records under §75.57(e)(1), except for paragraph (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), for 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;Page **738** of **763** (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 acquisiti on and handling system (DAHS) verification under §75.59(e) of this chapter. (c) You must keep records of the calculations you performed to determine the hourly and total CO 2 mass emissions (tons) for: (1) Each operating month (for all affected EGUs); (2) E ach compliance period, including, each 12
- operating month compliance period. (d) Consistent with §60.5520 , you must keep records of the applicable data recorded and calculations performed that you used to determine your affected EGU’s gross or net energy output for each operating month. (e) You must keep records of the calculations you performed to determine the percentage of valid CO 2 mass emission rates in each compliance period. (f) You must keep records of the calculations you performed to assess compl iance with each applicable CO 2 mass emissions standard in Table 1 or 2 of this subpart. (g) You must keep records of the calculations youPage **739** of **763** performed to determine any site
- specific carbon
-based F - factors you used in the emissions calculations (if applicable ). **§60.5565 In what form and how long must I keep my records?** (a) Your records must be in a form suitable and readily available for expeditious review. (b) You must maintain each record for 3 years after the date of conclusion of each compliance period. (c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to §60.7. Records that are accessible from a central location by a computer or other means that instantly provide access at the site meet this requirement. You may maintain the records off site for the remaining year(s) as required by this subpart. **Other Requirements and Information §60.5570 What parts of the General Provisions apply to m** **y affected EGU?**  Notwithstanding any other provision of this chapter, certain parts of the General Provisions in §60.1 through 60.19, listed in Table 3 to this subpart, do not apply to your affected EGU. **§60.5575 Who implements and enforces this subpart?** (a ) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, orPage **740** of **763** tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency. (b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate. (1) Approval of alternatives to the emission standards. (2) Approval of major alternatives to test methods. (3) Approval of major alternatives to monitoring. (4) Approval of major alternatives to recordkeeping and reporting. (5) Performance test and data reduction waivers under §60.8(b). **§60.5580 What definitions apply to this subpart?** As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions of this part).Page **741** of **763** Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating. Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis, as determined by the physical design and characteristics of the EGU at ISO conditions. For a stationary combustion turbine, base load ra ting includes the heat input from duct burners. Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent
- refined coal, gasified coal (not meeting the definition of natural gas), coal
- oil mixtures, and coal -water mixtures are included in this definition for the purposes of this subpart. 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 other organic and inorganic material. Combined cycle unit means an electric generating unit that
uses a stationary combustion turbine from which the heat fromPage **742** of **763** the turbine exhaust gases is recovered by a heat recovery steam generating unit (HRSG) to generate additional electricity. Combined heat and power unit or CHP unit, (also known as “cogeneration”) means an electric generating unit that that use a steam- generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy source. Design efficiency means the rated overall net efficiency (e.g., electric plus useful thermal output) on a lower heating value basis at the base load rating , at ISO conditions , and at the maximum useful thermal output (e.g., CHP unit with condensing steam turbines would determine the design efficiency at the maximum level of extraction and/or bypass) . Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by the Ame rican Society of Testing and Materials in ASTM D396 (incorporated by reference, see §60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see §60.17); kerosene, as de fined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see §60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see §60.17); or biodiesel blends a s defined by the American Society ofPage **743** of **763** Testing and Materials in ASTM D7467 (incorporated by reference, see §60.17). Electric Generating units or EGU means any steam generating unit, IGCC unit, or stationary combustion turbine that is subject to this rule (i. e., meets the applicability criteria) Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke
- oven gas, synthetic gas, and gasified coal. Gross energy output means: (1) For stationary combustion turbines and IGCC, the gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output. (2) For steam generating units, the gross electric or mechanical output from the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output;Page **744** of **763** (3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a 12
- operating month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxilia ry load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output. 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 stati onary combustion turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid
derived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid
- derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the EGU during operation.Page **745** of **763** 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), generate electri city and/or thermal energy, or to enhance the performance of the affected EGU. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal
- derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable CO 2 content or heating value. Net -electric sales meansPage **746** of **763** (1) The gross electric sales to the utility power distribution system minus purchased power; or (2) For combined heat and power facilities where at least 20 .0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on an annual basis, the gross electric sales to the utility power dist ribution system minus purchased power of the thermal host EGU or facilities. (3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net
- electric sales. (4) Electric sales that that res ult from a system emergency are not included when calculating net
- electric sales. Net -electric output means: the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer l osses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means:Page **747** of **763** (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 at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12
- operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output; Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual 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 a ffected EGU at any time. Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Potential electric output means 33 percent or the base load rating design efficiency at the maximum electric production rate (e.g., CHP units with condensing steam turbines will operate at maximum electric production) , whichever is greater, multiplied by the base load ratingPage **748** of **763** (expressed in MMBtu/h) of the EGU, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient affected EGU with a 100 MW (341 MMBtu/h) fossil fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity). Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 oF)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb . Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, pos t - combustion emission control technology, and any ancillary components and sub
components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus anyPage **749** of **763** integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self
-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment. System emergency means Useful thermal o utput means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output), or to supply energy to a pollution control device at the affected EGU. Useful thermal output for affected EGU(s) withPage **750** of **763** no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s )) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. System emergency means any abnormal system condition that the Regional Transmission Organizations (RTO), Independent System Operat ors (ISO) or control area Administrator determines requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore call for maximum generation resources to operate in the affected area, or for the specific affected facility to operate to avert loss of load. Valid data means quality
- assured data generated by continuous monitoring systems that are installed, operated, and maintained ac cording to part 75 of this chapter. For CEMS, the initial certification requirements in §75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality
- assured data are reported under this subpart; for on
-Page **751** of **763** going quality assurance , the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before quality
- assured data are reported under this subpart (except for qualifying commercial billing meters under se ction 2.1.4.2 of appendix D), and for on
- going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 of this chapter apply (except for qualifying commercial billing meters). Violation means a specified averaging period over which the CO 2 emissions rate is higher than the applicable emissions standard located in Table 1 or Table 2 of this subpart.Page **752** of **763 Table 1 of Subpart TTTT of Part 60**  **– CO** **2 Emission Standards for**  **Affected Steam Generating Units and Integrated Gasification Combined Cycl** **e Facilities that Commenced Construction 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 minimum of 3 signi**  **ficant figures and numerical values of less than 1,000 have**

**a minimum of 2 significant figures Affected EGU**  **CO 2**  **Emission Standard** Newly constructed steam generating unit or integrated gasification combined cycle (IGCC) 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 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 **753** of **763 Table 2 of Subpart TTTT of Part 60**  **– CO** **2 Emission Standards for**  **Affected Stationary Combustion Turbines that Commenced Construction after January 8, 2014 and Reconstruction after June**  **18, 2014 (net energy output -** **based standards as approved by the Administrator)**  **Note: numerical values of 1,000 or greater have a minimum of 3**  **significant figures and numerical values of less than 1,000 have**

**a minimum of 2 significant figures Affected EGU**  **CO 2**  **Emission Standard**594 Newly constructed or reconstructed stationary combustion turbine that supplies more than the design efficiency times the 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 ene rgy 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 the design efficiency times the 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 CO2 per gigajoule (GJ) of heat input (120 lb CO2/MMBtu)

Stationary combustion turbine that combusts 90% or less natural gas on a heat input basis on a 12
- operating month rolling average basis. 69 kg CO2/GJ of heat input (160 lb/MMBtu)

594 See procedures for establishing and revising the compliance option under § 60.5520.Page **754** of **763 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 **755** of **763** §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 **756** of **763 PART 70** **— STATE OPERATING PERMIT PROGRAMS**  3. The authority citation for part 70 continues to read as follows: **Authority** : 42 U.S.C. 7401 et seq. 4. Section 70.2 is amended by revising the introductory 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 calculation) , which is used only for purposes of § 70.9(b)(2), means any regulated air pollutant except the following:

* * * * * (4) Greenhouse gases.
* * * * * 5. Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding paragraph (b)(2)(v) to read as follows: **§70.9 Fee determi** **nation and certification.**

* * * * * (b) * * * (2)(i) The Administrator will presume that the fee schedulePage **757** of **763** 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 ye ar [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and any GHG cost adjustment required under paragraph (b)(2)(v) of this section.
* * * * * (v) GHG cost adjustment . The amount calculated in paragraph (b)(2)(i) of this section shall be increased by the GHG cost adjustment determined as follows: For each activity identified in the following table, multiply the number of activities performed by the permitting authority by the burden hours per activity, and then calculate a total number of burden hours for all activities. Next, multiply the burden hours by the average cost of staff time, including wages, employee benefits and overhead.
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 **758** of **763 PART 71** **— FEDERAL OPERATING PERMIT PROGRAMS**  6. The authority citation for part 71 continues to read as follows: **Authority** : 42 U.S.C. 7401 et seq. 7. Section 71.2 is amended by removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated pollutant (for fee calculation).” The revisions and additions read as follows: **§71.2 Definitions.** 

* * * * * Regulated pollutant (for fee calculation) , which is used only for purposes of §71.9(c), means any “ regulated air pollutant ” except the following:

* * * * * (4) Greenhouse gases.
* * * * * 8. Section 71.9 is amended by: a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and b. Adding paragraph (c)(8). The revisions and additions read as follows: **§71.9 Permit fees.** 

* * * * *Page **759** of **763** (c) * * * (1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of: (i) $32 per ton (as adju sted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and (ii) Any GHG fee adjustment required under paragraph (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 t on (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and (B) Any GHG fee adjustment required under paragraph (c)(8) of this section.

* * * * *Page **760** of **763** (3) For part 71 programs that are administered by EPA with contractor assistance, the per ton fee shall vary depending on the extent of contractor involvement and the cost to EPA o f contractor assistance. The EPA shall establish a per ton fee that is based on the contractor costs for the specific part 71 program that is being administered, using the following formula: Cost per ton=( E ×32)+[(1 − E )×$ C ] Where E represents EPA's proportion of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1
- E represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed by using the following formula: C =[ B + T + N ] divided by 12,300,000 Where B represents the base cost (contractor costs), where T represents travel costs, and where N represents nonpersonnel data management and tracking costs. In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section. (4) For programs that are delegated in part, the fee shall be computed using the following formula: Cost per ton=( E ×32)+( D ×24)+[(1 − E
− D )×$ C ] Where E and D represent, respectively, the EPA and delegate agency proportions of total effort (expressed as a percentage ofPage **761** of **763** total effort) needed to administer the part 71 program, 1 − E − D represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed using the formula for contractor assistance cost found in paragraph (c)(3) of this section and shall be zero if contractor assistance is not utilized. In addition, each part 71 source s hall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section.

* * * * * (8) GHG fee adjustment . The annual fee shall be increased by a GHG fee adjustment for any source that has initiated an activity listed in the following table since the fee was last paid. The GHG fee adjustment shall be equal to the set fee provided in the table for each activit y that has been initiated since the fee was last paid:

Activity Set fee GHG completeness determination (for initial permit or updated application) GHG evaluation for a permit modification or related permit action GHG evaluation at permit renewal $2,236 $364 $520
* * * * * **PART 98 —**  **MANDATORY GREENHOUSE GAS REPORTING**Page **762** of **763** 9. The authority citation for part 98 is revised to read as follows: Authority: 42 U.S.C. 7401
- 7671q. **Subpart PP**

**— Suppliers of Carbon Dioxide**  10. 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 this part and transfer CO2 to any facilities that are subject to subpart RR of this part, you must: (1) Report the facility identification number associated with the annual GHG report for the subpart D facility, (2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to which CO2 is transferred, and (3) Report the annual quantity of 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 **763** of **763** (d) Facilities subject to §98. 426(h) must retain records of CO 2 in metric tons that is transferred to each subpart RR facility.