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Page **1** of **208** EO 12866 EGU GHG NSPS preamble 2060_AQ91 11_04_11.docx

**ENV I** **RONMENTAL PROTECTION AGENCY**

**40 CFR Part 60 [**  **EPA -** **HQ -** **OAR -**  **2011 -**  **0660 ;**  **FRL -**  **]**

**RIN 2060**  **- AQ91**  **Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility**  **Generating Units**

**AGENCY:** Environmental Protection Agency (EPA) . **ACTION:** Proposed rule. **SUMMARY:** The United States EPA is proposing new source performance standards for emissions of carbon dioxide (CO 2 ) for new affected fossil - fuel - fired electric utilit y generating units (EGUs ). The EPA is proposing these requirements because CO 2 is a greenhouse gas (GHG) and power plants are the country’s largest stationary source emitters of GHG s . The EPA in 2009 found that by causing or contributing to climate change, GHGs endanger both the public health and the public welfare of current and future generations. The proposed requirements for new sources would require new fossil - fuel - fired EGUs greater than 25 megawatt electric to meet a standard of 1,000 pounds of CO 2 per megawatt hour, based on the performance of widely used natural gas combined cycle technology. New coal - fired units could meet the*********E.O. 12866 Review**

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Page **2** of **208** standard either by employing carbon capture and storage (CCS) 1 of approximately 50% of the CO 2 in the exhaust gas at star tup, or through later application of more effective CCS to meet the standard on average over a 30 - year period. EPA is not proposing standards of performance for existing EGUs whose CO 2 emissions increase as a result of install ation of pollution controls fo r conventional pollutants , or for proposed EGUs, which are referred to here as transitional sources, that have acquired a complete preconstruction permit by the time of this proposal and that commence construction within 12 months of this proposal. As a re sult, those sources would not be subject to the standards of performance proposed in today’s rule . At a future date , EPA intends to promulgate emission guidelines for state s to develop plans reducing CO 2 emissions from existing fossil - fuel - fired EGUs . **DAT ES:**  Comments . Comments must be received on or before [INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE] . Under the Paperwork Reduction Act (PRA) , since the Office of Management and Budget (OMB) is required to make a decision concerning the information collection request between 30 and

1 Throughout this preamble, we refer to ‘carbon capture and storage’ or CCS. By this, we mean the use of a technology for separating and capturing CO 2 from the flue gas or syngas stream with subsequent compression and transportation to a suitable location for long term storage and monitoring . Many references refer to CCS as ‘carbon capture and sequestration’. In this preamble, ‘storage’ and ‘sequestration’ mean the same thing and the words are used interchangeably.*********E.O. 12866 Review**

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Page **3** of **208** 60 days after [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE], a comment to the OMB is best assured of having its full effect if the OMB receive s it by [INSERT THE DATE 30 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE]. Public Hearing . The EPA will hold 3 public hearings on this proposal. The dates, times, and locations of the public hearings will be announced s eparately. Oral testimony will be limited to 5 minutes per commenter. The EPA encourages commenters to provide written versions of their oral testimonies either electronically or in paper copy. Verbatim transcripts and written statements will be included i n the rulemaking docket. If you would like to present oral testimony at one of the hearings, please notify Ms. Pamela Garrett, Sectors Policies and Programs Division (C504

– 03), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541

– 7966; email: garrett.pamela@epa.gov. Persons wishing to provide testimony should notify Ms. Garrett at least 2 days in advance of the public hearings. The public hearing will provide interested parties the opportunity to present data, views, or arguments concerning the proposed rule. The EPA officials may ask clarifying questions during the oral presentations, but will not respond to the presentations or comments at that time. Written statements and supporting information submitted*********E.O. 12866 Review**

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Page **4** of **208** during the comment period will be considered with the same weight as any oral comments and supporting information presented at the public hearing. For updates and additional information on the public hearings, please check the EPA’s website for this rulemaking, [add website address here]. **ADDRESSES:** Comments . Submit your comments, identified by Docket ID No. EPA- HQ - OAR- 2011 - 0660, by one of the following methods: At the website http://www.regulations.gov : Follow the instructions for submitting comments. At the website http://www.epa.gov/oar/docket.html : Follow the instructions for submitting comments on the EPA Air and Radiation Docket web site. E -mail : Send your c omments by electronic mail (e -mail) to a - andr - docket@epa.gov , Attn: Docket ID No. EPA- HQ - OAR- 2011 - 0660 . Fa csimile : Fax your comments to (202) 566 - 9744, Attn: Docket ID No. EPA- HQ - OAR- 2011 - 06 60 . Mail : Send your comments to EPA Docket Center, U.S. EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 20460, Attn: Docket ID No. EPA- HQ - OAR- 2011 - 0660 . Pl ease include a total of two copies. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 725 17 th St. NW,*********E.O. 12866 Review**

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Page **5** of **208** Washington, DC 20503. Hand Delivery or Courier : Deliver your comments to the EPA Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW, Room 3334, Washington, DC, 20460, Attn: Docket ID No. EPA- HQ - OAR- 2011 - 0660. Such deliveries are accepted only during the Docket’s normal hours of operation (8:30 a.m. to 4:20 p.m., Monday through Friday, excluding legal holidays), and special arrangements should be made for deliveries of boxed information. Instructions : All submissions must include agency name and docket ID number ( EPA- HQ - OAR- 2011 - 0660). The EPA’s policy is that all comments received will be included in the public docket without change and may be made available online at http://www.regulations.gov , including any personal information provided, unless the comment includes inf ormation claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through http://www.regulations.gov or e -mail. Send o r deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404 - 02), Office of Air Quality Planning and Standards, U.S. EPA, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA- HQ - OAR- 2011 - 0660 . Clearly*********E.O. 12866 Review**

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Page **6** of **208** mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD - ROM that you mail to the EPA, mark the outside of the disk or CD - ROM as CBI and then identify electronically within the disk or CD - ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclus ion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. The EPA requests that a separate copy of your comments also be sent to the contact person identified below (see **FOR FURT HER**  **INFORMATION CONTACT ).**  If the comment includes information you consider to be CBI or otherwise protected, a copy of the comment that does not contain the information claimed as CBI or otherwise protected should be sent. The www.regulations.gov website is an “anonymous access” system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through http://www.regulations.gov , your email address will be automatically captured and included as part of the comment that is placed in the*********E.O. 12866 Review**

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Page **7** of **208** public docket and made available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD - ROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. Docket : All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not public ly available (e.g., CBI 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 electronic ally in http://www.regulations.gov or in hard copy at the EPA Docket Center, EPA West, Room 3334, 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. Visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm for additional information about the EPA’s public docket.*********E.O. 12866 Review**

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Page **8** of **208** In addition to being available in the docket, an electronic copy of this proposed rule will also be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed rule will be posted on the TTN’s policy and guidance page for newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg/ . The TTN provides information and technology exchange in various areas of air pollution control. **FOR FURTHER INFORMATION CONTACT:** 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 or 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 . **SUPPLEMENTARY INFORMATION:** Acronyms . A number of acronyms are used in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference purposes, the following terms and acronyms are defined as follows : AB Assembly Bill AEP American Electric Power AEO Annual Energy Outlook ANSI American National Standards Institute*********E.O. 12866 Review**

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Page **9** of **208** ASME American Society of Mechanical Engineers ASTM American Society for Testing of Materials BSER Best S ystem of Emission Redu ction Btu/kWh British Thermal Units per Kilowatt Hour Btu/lb British Thermal Units per Pound CAA Clean Air Act CBI Confidential Business Information CCS Carbon Capture and Storage CEMS Continuous Emissions Monitoring System CH 4 Methane CHP C ombined Heat and P ower 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 E fficiency Resource S tandards EGU E lectric Utility Generating Units EIA Energy I nformation Administration EO Executive Order EOR Enhance Oil Recovery EPA Environmental Protection Agency FR Federal Register GHG Greenhouse Gas H 2 Hydrogen Gas HAP Hazardous Air Pollutant HFC Hydrofluorocarbon HRSG Heat Recovery Steam Generator IGCC I ntegrated Gasification C ombined C ycle IPCC Intergovernmental Panel on Climate Change IPM Integrated Planning Model kg/MWh Kilogram per Megawatt Hour kJ/kg Kilojoules per Kilogram kWh Ki lowatt Hour lb CO 2 /MMBtu P ound of CO 2 per Million B ritish Thermal Unit lb CO 2 /MWh Pound of CO 2 per Megawatt Hour lb CO 2 /yr Pound of CO 2 per Year lb/lb
-mole Pound per Pound-Mole MATS Mercury and Air Toxic Standards MW Megawatt MWe Megawatt Electric MWh Megawatt Hour N 2 O Nitrous Oxide NAAQS National Ambient Air Quality S tandards*********E.O. 12866 Review**

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Page **10** of **208** NAICS North American Industry Classification System NAS National Academy of Sciences NETL Nationa l Energy Technology Laboratory NGCC Natural Gas Combined Cycle NRC National Research Council NSPS New Source Performance Standards NSR New Source Review NTTAA National Technology Transfer and Advancement Act O 2 Oxygen OMB Office of Management and Budget PC Pulverized Coal PFC Perfluorocarbon PM Particula te Matter PM2.5 Fine Particulate Matter PRA Paperwork Reduction Act PSD Prevention of Significant Deterioration RCRA Resource Conservation and Recovery Act RFA Regulatory Flexibility Act RGGI Regional Greenhouse Gas Initiative RIA Regulatory Impact Analysis RPS Renewable Portfolio Standard SBA Small Business Administration SCC S ocial Cost of Carbon SF 6 Sulfur Hexafluoride SIP State Implementation Plan SO 2 Sulfur Dioxide SSM S tartup, S hutdown, and Malfunction Tg Teragram Tpy Tons per Year TSD Technical Support Document TTN Technology Transfer Network TVA Tennessee Valley Authority UIC Underground Injection Control UMRA Unfunded Mandates Reform Act of 1995 U.S. United States USGCRP U.S. Global Climate Research Prog ram VCS Voluntary Consensus S tandard WWW Worldwide Web Organization of This Document . The information presented in this preamble is organized as follows: I. General Information*********E.O. 12866 Review**

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Page **11** of **208** A. Executive Summary B. Does this action apply to me? II. Background A. Statutory Background for this Rule B. Overview of Climate Change Impacts from GHG Emissions C. GHGs from EGUs D. Litigation Directly Leading to this Rule E. Coordination with Other Rulemakings III. Summary of the Proposed Requirements for New Sources A. What is the affected source? B. What emission s limitations must I meet? C. What are the startup, shutdown, and malfunction requirements? D. What are the continuous monitoring requirements? E. What are the emissions performance testing requirements? F. What are the continuous compliance requi rements? G. What are the notification, recordkeeping, and reporting requirements? IV. Rationa le for the Proposed Standards: New Sources A. How did the EPA establish the emission limits? B. How did the EPA determine the other requirements for the proposed standards? V. Implications for PSD and Title V Programs A. Overview B. Implications for PSD Program C. Implications for Title V Program VI. Discussion of Modified Sources A. CAA Section 111 Requirements B. Timing for Promulgation of Standards of Performance for Modificati ons VII. Impacts of the Proposed Action A. What are the air impacts? B. What are the energy impacts? C. What are the compliance costs? D. How will this proposal contribute to climate change protection? E. What are the economic and employment impacts? F. What are the benefits of the proposed standards? VIII. Request for Comments IX. Statutory and Executive Order Reviews A. Executive Order 12866 : Regulatory Planning and Review, and Executive Order 13563 : Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 601 et seq . D. Unfunded Mandates Reform Act of 1995*********E.O. 12866 Review**

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Page **12** of **208** E. Executive Order 13132 : Federalism F. Executive Order 13175 : Consultation and Coordination With I ndian 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 J. Executive Order 12898 : Federal Actions to Address Environmental Justice in Minority Populations and Low- Income Populations **I. General Information** A. Executive Summary 1. Overview In this rulemaking , the EPA proposes to limit GHG emissions from new fossil - fuel - fired power plants by limiting CO 2 emissions . I n 2009 , the EPA issued a finding that GHG air pollution may reasonably be anticipated to endanger Americans’ public health and welfare, now and in the future, by contributing to climate change. Fossil - fueled power plants emit more GHG emissions than any other stationary source category in the United States, and among new GHG emissions sources, the largest individual sources are in this source category. Th is rulemaking proposes federal standards of performance for new fossil fuel - fired power plants that can be met with existing technology. Note that in this preamble, while we refer to these sou rces, interchangeably, as power plants, steam generating units, affected sources, fossil - fuel - fired electric generating units , covered EGUs,*********E.O. 12866 Review**

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Page **13** of **208** or, simply, EGUs , the proposed standards apply to only those sources identified in Section III.A. as the affected s ource category . 2. Why is the EPA proposing this rule? This proposed rule reflects the EPA’s common - sense approach to reducing CO 2 and other GHG emissions , which by caus ing climate change, pose a serious threat to public health and welfare. The EPA is focus ing first on reducing emissions from the largest emitters through measures with reasonable costs . The EPA is proposing to control CO 2 pollution from fossil - fuel - fired power plants because they are responsible for 40 percent of all U.S. anthropogenic GHG emissions. 2 Individual new power plants powered by coal are among the largest individual new sources of GHGs. Furthermore, technology exists that can be readily and cost - effectively used to reduce GHG emissions from these sources . Thus, this proposed rule is a rational first step to control GHG emissions from the largest categories of stationary sources under CAA section 111 . a . The Serious Threat of Climate Change to the Public’s Health and Welfare. Climate change, including global warming, is a significant threat to the global environment. The National Research Council (NRC)

2 From information in Table 2 - 1 from ‘Inventory of U. S. Greenhouse Gas Emissions and Sinks: 1990

– 2009’, U. S. Environmental Protection Agency, EPA 430 - R- 11 - 005, April 2011.*********E.O. 12866 Review**

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Page **14** of **208** of the National Academies 3 stated in a 2011 report, “Each additional ton of greenhouse gases emitted commits us to further chan ge and greater risks. In the judgment of the [NRC] Committee on America's Climate Choices, the environmental, economic, and humanitarian risks of climate change indicate a pressing need for substantial action to limit the magnitude of climate change and to prepare to adapt to its impacts.” 4 Action to reduce emissions is warranted because, as the EPA stated in its 2009 Endangerment Finding 5 , GHGs endanger the public health and public welfare of current and future generations. The anthropogenic buildup of GHGs in the atmosphere is very likely (90 to 99 percent probability) the cause of most of the observed global warming over the last 50 years . 6 Based on the Endangerment Finding and its underlying TSD 7 , reasons to reduce GHG emissions include the following:

3 The National Academies comprise the National Academy of Sciences, National Academy of Engineering, Institute of Medicine and National Research Council. 4 National Research Council (2011) America’s Climate Choices , Committee on America’s Climate Choices, Board on Atmospheric Sciences and Climate, Division on Earth and Life Studies, The National Academies Press, Washington, DC. 5 EPA, “ Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act” (74 FR 66,496; Dec. 15, 2009). http://epa.gov/climatechange/endangerment.html 6 Endangerment Finding at 74 FR 66,518, which notes that the 2007 conclusion of the Intergovernmental Panel on Climate Change was re - confirmed by the June 2009 assessment by the U.S. Global Change Research Program. 7 EPA, “Technical Support Document for Endangerment and Cause or Contribute Findings For Greenhouse Gases under Section 202(a) of the Clean Air Act, Dec. 9, 2009.” Both the Federal Register Notice and the TSD for*********E.O. 12866 Review**

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Page **15** of **208**  The key effects of climate change observed to date and projected to occur in the future include, but are not limited to, more frequent and intense heat waves, more severe wildfires, degraded air quality, heavier and more frequent downpours and flooding, in creased drought, greater sea level rise and storm surge , more intense storms, harm to water resources, continued ocean acidification, harm to agriculture, and harm to wildlife and ecosystems.

 These effects are anticipated to result in premature deaths, il lnesses, damage to property and infra structure, and other harm to people’s welfare in the U.S .
 Those “most vulnerable” to climate related health effects, such as children, the elderly and the poor

– and future generations -

- face disproportionate risks. 8

 Human - induced climate change impacts have the potential to be far - reaching and multidimensional, though not all risks and potential impacts can be quantified. 9

 A supporting consideration is that c limate change impacts in certain regions of the world (poten tially leading for example to Endangerment and Cause or Contribute Findings are found in the public docket established for the endangerment rulemaking, Docket No. EPA

–OAR

– 2009

– 0171 and at http://epa.gov/climatechange/endangerment.html. 8 Endangerment Finding, 74 FR 66498. 9 Endangerment Finding, 74 66497.*********E.O. 12866 Review**

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Page **16** of **208** food scarcity, conflicts or mass migration) may exacerbate problems that raise humanitarian, trade and national security issues for the United States. 10 The TSD further notes that some risks , such as the extinction of many species, would be irreversible. 11 Also, the TSD points to research on the potential for “abrupt changes” 12 which have uncertain or low probability but high potential impact. The NRC has said abrupt changes are an important consideration because, if triggered, they could occur so quickly and unexpectedly that human or natural systems would have difficulty adapting to them. 13 Examples include severe drought in subtropical areas, release of large amounts of GHGs stored in the sea floor and frozen Arctic soil s , and rapid disintegration of Greenland ice or collapse of the West Antarctic ice sheet leading to many feet of sea level rise. 14 The special characteristics of GHGs make it important to take initial steps to control the largest emissions categories without delay. Unlike most traditional air pollutants, GHGs persist in the

10 Endangerment Finding, 74 FR 66535. 11 Endangerment TSD, p. 136 12 Endangerment TSD, p. 75 - 78. The U.S. Climate Change Science Program defined “abrupt change” as a “large - scale change in the climate system that takes place over a few decades or less, persists (or is anticipated to persist) for at least a few decades, and causes substantial disruptions in human and natural systems.” Synthesis and Assessment Product (SAP) 3.4: Abrupt Climate Change (2008). 13 Endangerment TSD, p. 75, citing National Research Council (2002) 14 Endangerment TSD , pp. 76 - 78*********E.O. 12866 Review**

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Page **17** of **208** atmosphere for time periods ranging from decades to millennia, depending on the gas. Greenhouse gases will continue to accumulate in the atmosphere at higher and higher concentrations each year unless substantial reductions in global emissions are achieved . The NRC notes that emissions reduction choices made today matter in determining the level of impacts experienced not just over the next few decades, but in the coming centuries and millennia. 15 Also, the longer that the U.S. and other countries take to reduce emissions, the steeper the future emissions reductions that will be required to limit global temperature increase to any given level. This proposed rule to reduce GHG emissions from the largest U.S. stationary source category will contribute to the emissions reductions required to slow or reverse the accumulation of GHG concentrations in the atmosphere, which is necessary to protect against projected climate change impacts and ri sks. Reducing GHG emissions reduces the impacts and risks articulated in the Endangerment Finding and TSD . b . The High Level of GHG Emissions from Fossil - Fuel - Fired P ower P lants and the Opportunities to Reduce these Emissions. Fossil - fuel fired power plant s comprise the largest category of stationary source

15 National Research Council (NRC) (2011). Climate Stabilization Targets. Committee on Stabilization Targets for Atmospheric Greenhouse Gas Concentrations; Board on Atmospheric Sciences and Climate, Division of Earth and Life Sciences, National Academy Press. Washington, DC.*********E.O. 12866 Review**

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Page **18** of **208** GHG emissions in the U . S. These sources account for 60 percent of U.S. stationary source GHG emissions, and 32 percent of total U.S. GHG emissions, based on 2009 data. 16 Furthermore, a range of technologies are available to reduce these EGU emissions. Most new power plants being built in the U.S. today are either natural gas - fired or are powered by renewable sources of energy, such as wind, and therefore generally produce significantly fewer emissions than existing coal - fired power plants. Coal - fired power plants can install CCS technology and can thereby limit their CO 2 emissions per MWh generated to levels similar to, or even lower than , those of natural gas - fired combine d cycle plants without CCS . Coal - fired power plants with CCS are be ing permitted and built today. There are also opportunities to reduce emissions at existing fossil - fired plants. For instance, the efficiency of much of the existing generation can be improved, lower emitting plants can be dispatched more often , and higher emitting plants can co - fire fuels , such as natural gas , with lower CO 2 intensity. c. Alignment with Industry’s Other CAA Obligations. Establishing the overall regulatory requirements for GHG emissions from new fossil fuel - fired power plants at this time is efficient because the EPA has
16 “Inventory of US GHG Emissions and Sinks” (April 2011); “Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Final Rule (GHG Reporting)” (September 2009).*********E.O. 12866 Review**

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Page **19** of **208** recently issued regulations to limit conventional pollutants (criteria and hazardous air pollutants) from these sources . Aligning the timing of these GHG rules with the rules for conventional pollutants give s the industry more regulatory certainty , will facilitate the industry’s investment decisions, and will help inform its compliance decisions to meet all of its CAA obligations. d. Promotion of Energy Diversity. This proposed rule is consistent with the president’s goal to ensure that “by 2035 we will generate 80% of our electricity from a diverse set of clean energy sources - including renewable energy sources like wind, solar, biomass and hydropower, nuclear power , efficient natural gas and clean coal.” 17 The propos ed rule will assist the deployment of CCS technology for new coal - fired power plants and create an incentive for the use of efficient natural gas - fired generation. Regulatory uncertainty may be hindering the development and deployment of CCS, as evidenced by American Electric Power (AEP) ’s recent deferral of a large scale CCS retrofit demonstration project on one of its coal - fired power plants because the state’s utility regulators would not approve CCS without a regulatory requirement to reduce CO 2 . 18 The standard established in

17 “Blueprint for a Secure Energy Future”, March 30, 2011 18 In a July 17, 2011, press release, AEP ’s chairman said, “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 v ital if owners of coal - fueled generation are to comply with potential future climate regulations without*********E.O. 12866 Review**

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Page **20** of **208** this proposal would help create the regulatory certainty that CCS is the path forward for new coal - fired generation. 3. Legal Proceedings Leading up to this Rulemaking. In April 2007, the U.S. Supreme Court ruled , in Massachusetts v. EPA , 19 that GHGs meet the definition of “air pollutant” in the CAA. This decision clarified that the authorities and requirements of the CAA , including section 111, apply to GHG emission s. As a result of this decision, the EPA obtained a voluntary remand from the U.S. Court of Appeals for the D istrict of C olumbia Circuit (the “Court”) to reconsider the EPA’s actions in a 2006 rulemaking for EGUs under CAA section 111, in which the EPA had pr omulgated standards for conventional air pollutants, but had declined to regulate GHG emissions. In part in response to threatened litigation over the EPA’s failure to act on the remand, the EPA agreed to propose today’s action to regulate GHG emissions fr om new EGUs. 4. Legal Basis for CAA Standards for Fossil - Fired Power Plants. a. General Legal Requirements. Clean Air Act s ection 111 establishes a several - step process for the EPA and the states to regulate air prematurely retiring efficient, cost - effective 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 to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share.” 19 549 U.S. 497 (2007).*********E.O. 12866 Review**

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Page **21** of **208** pollutants from stationary sources. First , the EPA must list categories of stationary sources that cause or contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. Then, the EPA must regulate emissions from new sources in the source category by issuing a standard of performance, which is defined 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 accoun t ... cost [and other factors]) ... has been adequately demonstrated.” New sources include new construction, and, as discussed below, modifications to existing sources as well as reconstructed sources. Standards of performance for new sources are often referred to as new source performance standards (NSPS). Clean Air Act section 111 also requires regulation of existing sources of certain pollutants

– in general, ones that are other than NAAQS pollutants or HAPs

– and provides the states the authority to act as the direct regulators. Regulation of new sources of those pollutants triggers a requirement that EPA also promulgate emission guidelines for existing sources. The states must then develop standards of performance based on those emission guidelines and submit those standards in state plans to the EPA for approval. The*********E.O. 12866 Review**

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Page **22** of **208** states have flexibility in applying the standards of performance to particular sources. CAA section 111(d)(1). b. Cause - or - Contribute - Significantly Finding for Power Plants and Endangerment Finding for GHG Air Pollution. The EPA is authorized to regulate GHGs from power plants based on earlier actions concerning endangerment. Before today’s rulemaking, the EPA listed different types of fossil - fuel - fired EGUs as source categories that caused or contributed significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. Specifically, the EPA listed boilers, including coal - fired boilers, and initially regulated them in subpart D of its regu lations under CAA section 111. Subsequent regulation of utility boi lers has been under subpart Da. The EPA listed combustion turbine engines and initially re gulated them under subpart GG. The combustion turbine engine portions of combined cycle facilities we re regulated under subpart GG. Heat recovery steam generators associated with combined cycle facilities with duct burners were regulated under either subpart Da or one of the industrial boiler regulations, depending on the specific characteristics of the heat recovery s team generator. To minimize the compliance burden for owners/operators of combined cycle facilities some monitoring harmonization was done, but 2 subp arts were still applicable. In 2005, EPA proposed subpart KKKK as a replacement for*********E.O. 12866 Review**

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Page **23** of **208** subpart GG and specifi cally covered the entire combined cycle facility under subpart KKKK such that only a single se t or requirements would apply. In that same year, EPA proposed to include Integrated Gasification Combined Cycle ( IGCC ) facilities under the applicability of subpart Da. The E PA is authorized to promulgate the rulemaking proposed today -- which would establish standards of performance for CO 2 emissions from EGUs currently in the Da and KKKK source categories -- because the EPA has already determined that both those source categories cause or contribute significantly to air pollution that may reasonably be expected to endanger public health or welfare. Clean Air Act section 111 does not require the EPA, as a prerequisite to regulating any particular air pollutant, to issue an endangerment finding or a cause - or - contribute - significantly finding for that air pollutant from that source category. As an alternative, the EPA solicits comment on whether CAA section 111 should be int erpreted to require that the EPA base its regulation of CO 2 emissions from EGUs on two findings: (i) a finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare; and (ii) a finding that CO 2 emissions from EGUs cause or contribute significantly to that air pollution. If section 111 were so interpreted, the EPA believes that (a) the 2009 Endangerment Finding, along with the EPA’s 2010 action denying*********E.O. 12866 Review**

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Page **24** of **208** petitions to reconsider that finding (which action reviewed scientific developments after the Endangerment Finding) would fulfill any requirement to make the endangerment finding concerning GHG air pollution; and (b) the large amount of CO 2 emissions from EGUs clearly exceeds the low applicability threshold upon which the EPA would make the cause - or - contribute - significantly finding. As another alternative, the EPA solicits comment on whether CAA section 111 should be interpreted to require that the EPA base its regulation of CO 2 emissions from EGUs on a rational basis for prot ection of the public health or welfare. If section 111 were so interpreted, the EPA believes that (i) its 2009 Endangerment Finding and 2010 denial of petitions to reconsider, by themselves, and particularly in conjunction with the National Academy of Scie nces’ assessment reports issued since then, coupled with (ii) the fact that EGUs are the largest stationary source emitters of CO 2 , provide a rational basis for regulating CO 2 emissions from EGUs. There is no reason to revisit the 2009 Endangerment Finding given recent scientific findings that strengthen the scientific conclusion that GHG air pollution endangers public health and welfare. 20

20 These recent scientific findings are described in section II of this notice, titled “Background.” See subsection II.B.3., “Climate Impacts Detailed in Recent NRC Assessments.” The legal options introduced here are presented in detail below in section IV.A.2, “Endangerment and Cause - or Contribute - Significantly Finding.”*********E.O. 12866 Review**

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Page **25** of **208** 5 . Summary of Today’s Proposed Requirements to Reduc e GHG Emissions from New Fossil - F ired Power Plants a. Revisions to Categories of EGUs. In today’s action, the EPA is proposing to combine electric utility steam generating units (boilers) (which are currently included in the Da category) and combined cycle units (including IGCC units) that generate electri city for sale and meet certain size criteria (which are currently included in the KKKK category), into a new category for new sources (the TTTT category ) . Today’s proposed rulemaking would not affect conventional air pollutants or s imple cycle turbines . 21 b. Requirements for New Sources. The EPA is proposing standards of performance that require that all new fossil - fuel - fired EGUs meet an electricity- output -based emission rate of 1,000 lb CO 2 /MWh of electricity generated on a gross basis . This proposed standard is based on the demonstrated performance of natural gas combined cycle ( NGCC ) units , which are currently in wide use throughout the country . C oal - , coal refuse - , and pet - coke - fired boilers and IGCC units should also be able to meet this standard by employing CCS technology. There are a number of coal - and pet - coke - fired EGU projects under development that include CCS . While a coal unit with CCS may be more expensive than NGCC generation, for reasons explained below , we 21 Thus, today’s rulemaking does not affect the Da and KKKK categories for conventional pollutants and does not affect the KKKK category for simple cycle turbines.*********E.O. 12866 Review**

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Page **26** of **208** expect the difference to decrease over time as CCS becomes less expensive. Accordingly, we include in today’s proposed rulemaking a compliance option under which affected sources that implement CCS could comply with the 1,000 lb CO 2 /MWh standard on a 30
- year average basis. Coal - and pet coke - fired EGUs that use this compliance alternative must also meet an immediate performance standard of 1, 800 lb CO 2 /MWh (gross) , which can be achieved by a “supercritical” efficiency level, during the period before installation of CCS. Under CAA section 111(b)(1)(B), the EPA is required to conduct a review of the new source standards in eight years and we intend at that time to review the availability and cost of CCS.
c . Requirements for Modifi cations . For purposes of today’s action , the EPA is not aware that any affected sources may be expected to take actions that would constitute “modifications” (as defined under the EPA’s regulations) and therefore be subject to requirements for new sources. As a result, the EPA is not proposing requirements for modifications. The EPA’s current regulations define a “modification” as a physical or operational change that increases the source’s maximum achievable hourly rate of emissions, but specifically exempt from that definition pollution cont rol projects, which are projects that entail the installation of pollution control equipment or systems.*********E.O. 12866 Review**

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Page **27** of **208** The actions that we expect EGUs to undertake in the foreseeable future that could increase the maximum achievable hourly rate of CO 2 emissions will constitute pollution control projects. In many cases, those projects will involve the installation of add- on control equipment required to meet CAA requirements for conventional air pollutants . These increases in CO 2 emissions will be small and will occur as a chemical byproduct of the operation of the control equipment. In other cases, those projects will involve equipment changes to meet the requirements of this rulemaking and will have the effect of increasing a source ’ s maximum achievabl e hourly emission rate, even while decreasing its actual emission rate. Because all of these actions will be treated as pollution control projects under EPA’s current NSPS regulations, they will be specifically exempted from the definition of modification. In addition, it is conceivable that EGUs may undertake other changes that may increase their capacity and, therefore, their maximum achievable hourly emission rate. It is possible that those changes would be so capital intensive that they would fall into the category of reconstructions, which also are not treated as modifications. Historically, it has been rare that actions by sources have been treated as modifications under the NSPS requirements.*********E.O. 12866 Review**

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Page **28** of **208** As a result, the EPA is not aware that any EGUs may reasonably be expected to undertake actions that would be defined as modifications. The EPA solicits comment on that issue, but in the meantime, the EPA is not proposing standards for modifications. The EPA does not believe that it currently has adequate informat ion as to the type s of action s , their costs, or the amount of resulting CO 2 emissions, on which to base a proposed standard of performance. Therefore , sources that undertake physical or operational changes that increase their maximum achievable hourly CO 2 emission rate will be treated as existing sources and thus not subject to the requirements proposed in this notice, although they would be subject to requirements that EPA intends to propose separately for existing EGUs. In the alternative, if these action s (i.e., projects that involve equipment changes to meet other CAA requirements and any other changes that increase maximum achievable emission rate of CO 2 ) were considered to be modifications, then the EPA is soliciting comment on what the appropriate standard(s) of performance for these modifications should be. However, to reiterate, the EPA is not proposing any standards of performance for these modifications at this time.*********E.O. 12866 Review**

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Page **29** of **208** d . Requirements for Transitional sources. The EPA is aware that approximately 18 p roposed EGUs have received CAA permitting authority approval for their preconstruction permits, but may not have “commenced construction ” by the date of today’s proposed rulemaking. For this proposed rule, these sources are referred to as “transitional sources.” We are aware that approximately seven of these permitted sources are planning to implement CCS to some degree. CAA section 111 provides by its terms that sources that have n ot “commenced construction” before the date of proposed standards for new sources will be subject to the NSPS when they do commence construction. The EPA’s regulations define “commenced construction” as, in general, undertaking a continuous program of cons truction or entering into a binding contract to do so. 40 CFR 60.2. Commenters have pointed out that absent an exemption, transitional sources will be subject to the same requirements that apply to new sources that did not obtain their permit before the da te of proposal, and these commenters have suggested that today’s proposed rule should treat transitional sources specially, in light of the substantial redesign that meeting such a standard would have and the impact that redesign would have on the schedule for a project that was nearly ready to commence construction. The transitional sources at issue are coal - fired EGUs that, absent special treatment,*********E.O. 12866 Review**

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Page **30** of **2 08**  would be subject to the standard of performance proposed in this rulemaking. In today’s proposed rulemaking, the EPA is not proposing a standard of performance for transitional sources that commence construction within 12 months of the date of this proposal. Upon finalization of this rulemaking without a standard of performance applicable to these sources, they will not be treated as new sources and therefore will not be subject to the specific limitations set forth in the final new source standards . These sources would remain obligated, by the terms of their permits, to construct and operate in accordance with their permits. In addition, these sources will be treated as existing sources and would be subject to any requirements a state promulgates to meet its obligations under section 111(d). Sources that do not commence construction within 12 months of the dat e of this proposed action will be subject to the standard of performance for new sources. e. Requirements for Reconstructed sources. The EPA’s CAA section 111 regulations provide that reconstructed sources are to be treated as new sources and, therefore, subject to new source standards of performance. The regulations define reconstructed sources as, in general, existing sources (i) that replace components to such an extent that the capital costs of the new components exceed 50 percent*********E.O. 12866 Review**

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Page **31** of **208** of the capital costs of an entirely new facility, and (ii) for which compliance with standards of performance for new sources is technologically and economically feasible. 40 CFR 60.15. We are aware that in theory, existing power plants may reconstruct, but we are not aware o f any that have announced plans to do . In addition, at this time the EPA does not have information to base a determination of what standards of performance will be technologically and economically feasible. In this proposed action, the EPA is taking comment on two different options. Option one would treat reconstructed sources the same as any other new source (e.g. subject to an emission limit of 1 , 000 lb CO 2 /MWh). The EPA believes that if the owner of a source plans to invest enough capital into an existing unit to reach the reconstructed threshold, it is likely with the intent of significantly increasing the life of the plant. The EPA does not intend to create a policy that would permit or encourage an owner to forego building a new clean facility, in favor of merely reconstructing an existing facility that operated with higher emissions." Alternatively, we are taking comment on a standard of 1 ,8 00 lb CO 2 /MWh (gross) . This would be consistent with the first phase requ irement for new sources availing themselves of the alternative compliance option for new sources. It would represent*********E.O. 12866 Review**

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Page **32** of **208** upgrading the unit to an efficiency level consistent with some of the best performing existing units. 6. Summary of Emissions Impacts, Cost s and Benefits We are projecting that there will be no construction of new coal - fired generation without CCS even absent this proposed rule. Therefore, we do not project that this proposed rule will impose costs upon sources. While this proposed rule will not have direct impact on U.S. emissions of greenhouse gases, it will send a strong signal both domestically and internationally. Domestically, this proposed rule will further stimulate investment in CCS technology, by making it clear that such technology does provide a clear path forward for coal. Internationally, this rule may encourage others to consider less GHG - intensive forms of power generation. B. Does this action apply to me ? The entities potentially affected by the proposed standards are shown in Table 1 below .

**T able**  **1 . P** **otentially A** **ffected E** **ntities a**  **Category NAICS** 

**Code Examples of Potentially Regulated**  **Entities** Industry 221112 Fossil fuel electric power generating units. Federal 221112 b Fossil fuel electric power generating*********E.O. 12866 Review**

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Page **33** of **208** Government 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 Include 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 classified 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 proposed action. To determine whether your facility, company, business, organization, etc., would be regulated by this proposed action, you should examine the applicability criteria in 40 CFR 60. 1 . If you have any questions regarding the applicabi lity 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). **II. Background** A. Statutory Background for this Rule C lean Air Act section 111 establishes mechanisms for controlling emissions of air pollutants from stationary sources. As a preliminary step, CAA section 111(b) (1)(A) requires the EPA to list categories of*********E.O. 12866 Review**

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Page **34** of **208** stationary sources that the Administrator, in his o r her judgment, finds “cause [] , or contribute [] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” 22 Once it has listed a source category, the EPA establishes “standards of performance” that apply to new sources , which are sources that are constructed , or that undertake modifications or reconstruction , after the EPA proposes the standards of performance for the relevant source category. CAA section 111(b)(1)(B). Specific statutory and regulatory provis ions define what constitutes a modification or reconstruction of a facility. An existing facility undertakes a modification if it undergoes “any physical change ... or change in the method of operation . . . which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” CAA section 111(a)(4) . The EPA’s regulations provide exemptions for several types of changes, including the installation of pollution control projects. 40 CFR 60.2, 60.14(e). An existing facility undertakes a reconstruction if it replaces components to such an extent that the capital cost s of the new equipment or components exceed 50 percent of what is believed to be the cost of a completely new facility. 4 0 CFR 60.15. In promulgating standards of performance, the EPA has

22 The EPA has made endangerment findings under this section for more than 60 stationary source categories and subcategories that are now subject to NSPS.*********E.O. 12866 Review**

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Page **35** of **208** significant discretion to create subcategories based on source type, class or size. CAA section 111(b)(2). Clean Air Act s ection 111(a)(1) defines a “standard of performance” as

– a standard for emissions of air pollutants which reflect s 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. We call this level of control the best system of emission reduction ( BSER ) . 23 The standard that the EPA develops, based on the BSER, is commonly a numerical emissions limit, expressed as a performance level ( e.g., a rate -based standard). Generally, the EPA does not prescribe a particular technological system that must be used to
comply with a standard of performance . Rather, sources remain free to elect whatever combination of measures will achieve equivalent or greater control of emissions. When the EPA establishes standards of performance for new sources of a pollutant that, in ge neral, is not regulated under the CAA section 109 requirements for NAAQS or regulated under the CAA section 112 requirements for HAPs, then, under CAA section 111(d) (1), the EPA must issue guidelines for states to regulate existing sources

23 This level of control has historically been referred to as best demonstrated technology (BDT).*********E.O. 12866 Review**

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Page **36** of **208** in the source ca tegory for that pollutant . EPA intends to propose those guidelines in a separate rulemaking at a later date . S ection 111(d) provides a different mechanism to regulate existing sources than CAA section 111(b) provides for new sources . Instead of giving the EPA direct authority to set national standards applicable to existing sources , section 111(d) (1) provides that the EPA shall establish a procedure similar to the procedure required under CAA section 110 (concerning state submission of state implementation plans (SIPs) to attain the NAAQS) for state s to develop plans that include standards of performance for those sources . Under the EPA’s regulations implementing section 111(d) , the EPA first develops regulations known as “emission guidelines , ” which establi sh binding requirements that state s are required to address when they develop standards of performance for their plans . 40 CFR 60.22. These state plans must be submitted to the EPA for approval. 40 CFR 60.23. In the event that a state does not adopt and submit a plan, or submit s a plan that the EPA disapproves, the EPA is then obligated to issue a federal plan. 40 CFR 60.27(c). B. Overview of Climate Change Impacts from GHG Emissions*********E.O. 12866 Review**

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Page **37** of **208** In 2009, the EPA Administrator issued the 2009 Endangerment Finding, 24 under CAA section 202(a)(1), as part of the process for promulgating the Light Duty Vehicle Rule. 25 With the Endangerment Finding, the Administrator found that elevated concentrations of GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare. The se adverse effects on public health and welfare are summarized here , and described in more detail in the RIA . As explained in the Endangerment Finding, EPA made this determination based primarily upon the recent, major assessments by the U . S . Global Change Research Program (US GCRP ) , Intergovernmental Panel on Climate Change ( IPCC ) , and the National Research Council ( NRC ). 26 In brief, these assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change problem, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review and acceptance. Below is a brief, non - comprehensive summary of effects noted in the Endangerment Finding and the assessment reports.

24 "Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act." 74 FR 66496 (December 15, 2009). 25 "Light - Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule." 75 FR 2532 4 (May 7, 2010). 26 74 FR 66510 - 66511.*********E.O. 12866 Review**

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Page **38** of **208** 1. Public Health Impacts Detailed in the 2009 Endangerment Finding C limate change threatens public health through a number of impacts such as increases in hot weather, ozone pollution, and the severity and frequency of extreme weather events. Children, the elderly, and the poor are among the most vulnerable to these climate related hea lth effects. By increasing higher average temperatures , climate change increas es the likelihood of heat waves, which are associated with increased deaths and illnesses . While climate change also leads to decreases in cold- related mortality, some evidence s uggests that the net impact on mortality is more likely to be adverse . Heat is already the leading cause of weather - related deaths in the U . S. Climate change is expected to increase ozone pollution over broad areas of the country including large population areas with unhealthy ozone levels . Ozone health studies indicate that elevated ozone increases risks of premature death, acute bronchitis, heart attacks, asthma aggravation, and other respiratory effects. Public health threats also stem from increases in intensity or frequency of extreme weather associated with climate change, such as increased hurricane intensity, increased frequency of intense storms and heavy precipitation. The assessment literature indicates that there is the potential for hurricanes t o become more intense , and*********E.O. 12866 Review**

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Page **39** of **208** there is some evidence that Atlantic hurricanes have already become more intense . Hurricanes and floods from human - induced climate change
can cause deaths, injuries, waterborne diseases, and mental health problems such as post - tr aumatic stress disorders . Drownings and other health impacts from coastal storms and storm surges are expected to increase due to rising sea levels. 2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding Climate change is expected to have numerous effects on public welfare. L arge areas of the country are at serious risk of reduced water supplies, increased water pollution , and increased occurrence of extreme events such as floods and droughts. Coastal areas face increased risks from storm and flooding damage to property, as well
as adverse impacts from sea level rise such as land loss due to inundation, erosion, wetland submergence, and habitat loss. Climate change is expected to result in an increase in peak electricity demand, and changes in extreme weather threaten energy, transportation, and water resource infrastructure. Climate changes may exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities. Over the 21 st century, climate change will fundamentally rearrange U.S. ecosystems.*********E.O. 12866 Review**

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Page **40** of **208** It is possible that in the next few decades, adverse effects in certain parts of the agriculture and forestry sectors -- such as enhanced pest and weed growth, increased ozone, changes in the intensity and f requency of droughts and heavy storms, and increased wildfires -- may be offset by benefits resulting from a stimulatory carbon dioxide effect and a longer growing season. However, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture, and forest productivity as temperatures continue to rise, with the potential for significant disruptions and crop failure. Human - induced climate change has the potential to be far - reaching and multidimensional . Given the long atmospheric lifetime of the six GHGs, which range from roughly a decade to centuries, future atmospheric greenhouse gas concentrations for the remainder of this century and beyond will be influenced not only by future emissions but indeed by prese nt - day emissions. The severity of all the described risks and impacts is likely to increase over time with accumulating GHG concentrations and the associated temperature increases and precipitation changes. Finally, these impacts are global, and may exacerbate problems that raise humanitarian, trade, and national security issues for the U.S. 3. Climate Impacts Detailed in Recent NRC Assessments*********E.O. 12866 Review**

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Page **41** of **208** Since EPA issued the 2009 Endangerment Finding, the NAS , which is a society established by an Act of Congress that is composed of distinguished scholars engaged in scientific and engineering research , has issued assessments with similar conclusions to those of the assessments upon which EPA based the Endangerment Finding . In May 2010, the NRC , which is the operating a rm of the NAS that conducts most of the science policy and technical work, published its comprehensive assessment, “Advancing the Science of Climate Change” (the 2010 NRC Assessment). 27 It concluded that “climate change is occurring, is caused largely by human activities, and poses significant risks for -- and in many cases is already affecting -- a broad range of human and natural systems.” 28 Furthermore, the NRC stated that this conclusion is based on findings that are “consistent with the conclusions of re cent assessments by the U.S. Global Change Research Program, the Intergovernmental Panel on Climate Change’s Fourth Assessment Report, and other assessments of the state of scientific knowledge on climate change.” 29 These are the same assessments that served as the primary scientific references underlying the 2009 Endangerment Finding. The 2010 NRC Assessment

27 NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. 28 NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. Page 3. 29 NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. Page 286.*********E.O. 12866 Review**

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Page **42** of **208** also warned of risks associated with abrupt changes and surprises that might occur when certain thresholds are crossed, such as the release of large quantities of GHGs stored in frozen soils in the Arctic or irreversible drying and desertification in the subtropics; and of potential for broad, “catastrophic” impacts on marine ecosystems resulting from ocean acidi fication. Another NRC assessment, “Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millenia”, was published in 2011 (the 2011 NRC Assessment) . This report found that climate change due to CO 2 emissions will persist fo r many centuries. The report also estimate s a number of specific climate change impacts, finding that every degree Celsius (o C ) of warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic sea ice extent, along with other precipitation and stream flow changes. The assessment also found that with an increase of 4 o C , the average summer would be as warm as the warmest summers of the past century , that for an increase of 1 to 2 o C the area burnt by wildfires in western North Ame rica will likely more than double, that coral bleaching and erosion will increase due both to warming and ocean acidification, and that sea level will rise 1.6 to 3.3 feet by 2100 in a 3 o C scenario. The assessment notes that many important aspects of climate change are difficult to quantify but that the risk*********E.O. 12866 Review**

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Page **43** of **208** of adverse impacts is likely to increase with increasing temperature, and that the risk of surprises can be expected to increase with the duration and magnitude of the warming. Importantly, these recen t NRC assessments represent another independent and critical inquiry of the state of climate change science, separate and apart from the previous IPCC , NRC, and USGCRP assessments. C. GHGs from Power Plants Fossil - fuel - fired electric utility generating uni ts are by far the largest emitters of GHGs, primarily in the form of CO 2 , among stationary sources in the U.S. This section describes the amount of those emissions and places that amount in the context of the national inventory of GHGs. The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks 30 (the U.S. GHG Inventory) to comply with existing commitments under the United Nations Framewor k Convention on Climate Change . Th is inventory , which includes recent trends , is presented by industrial sectors . It is the source for the information provided in Table 2 below concerning total U.S. anthropogenic emissions and sinks of GHGs and CO 2 emissions, by industrial sector

– including fossil fuel - fired EGUs -- for the years 1990, 2000 , and 2 009. **T able**  **2 . U.S. G** **HG E** **missions and**  **S inks**  **by S** **ector (**  **teragram carbon**

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

– 2009”, Report EPA 430 - R- 11 - 005, United States Environmental Protection Agency, April 15, 2011.*********E.O. 12866 Review**

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Page **44** of **208 dioxide equivalent (**  **Tg CO 2**  **Eq. )**  **) 31**  **S ECTOR**  **1990 2000**  **2009** Energy 5,287.8 6,168.0 5,751.1 Industrial Processes 315.8 348.8 282.9 Solvent and Other Product Use 4.4 4.9 4.4 Agriculture 383.6 410.6 419.3 Land Us e, Land- Use Change and Forestry (Emissions) 15.0 36.3 25.0 Waste 175.2 143.9 150.5 Total Emissions 6,181.8 7,112.7 6,633.2 Land Use, Land- Use Change and Forestry (Sinks) (861.5) (576.6) (1,015.1) Net Emissions (Sources and Sinks) 5,320.3 6,536.1 5,618.2 Energy- related CO 2 emissions are the largest contributor to total U.S. GHG emission s, representing 86.7 percent of total 2009 GHG emissions. In 2009, the electric power sector

– - consisting of those entities whose primary business is the generation of electricity

– - accounted for 40 percent of all energy- related CO 2 emissions. The transportation sector , with emissions principally from the combustion of gasoline, diesel, and jet fuel , was the second- largest source, at 32 percent of the total. Other energy- related CO 2 emission sources included industrial, residential , and commercial fossil fuel combustion, natu ral gas and petroleum syst ems, and incineration of waste.

31 From Table 2 - 3 of the EPA GHG Emissions and Sinks Inventory, EPA 430 - R- 11 - 005.*********E.O. 12866 Review**

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Page **45** of **208** Direct fuel use in the residential and commercial sectors accounted for 26 percent of total CO 2 emissions in 2009. Total CO 2 emissions from fossil - fuel - fired EGUs , for years 1990, 2000 and 2009,
are shown below in Table 3 . **T able**  **3 . U.S.**  **GHG Emissions from Generation of Electricity from**

**Combustion of Fossil Fuels (Tg CO 2**  **Eq.)**

We are aware that N 2 O (and to a lesser extent, CH 4 ) may be emitted from fossil - fuel - fired EGUs, especially from coal - fired circulating fluidized bed combustors and from units with selective catalytic reduction and selective non - catalytic reduction systems installed for NOX control. We are not proposing separate N 2 O or CH 4 emission limits or an equivalent CO 2 emission limit in today’s action because of a lack of available data for these affected sources. Additional information on the quantity and significance of emissions and on the availability of cost effective controls would be needed before proposing standards for these pollutants. The estimated **GHG E MISSIONS**  **1990 2000**  **2009** Total CO 2 from fossil fuel combustion 1,820.8 2,296.9 2,154.0

- from coal 1,547.6 1,927.4 1,747.6

- from natural gas 175.3 280.8 373.1

- from petroleum 97.5 88.4 32.9 From use of limestone and dolomite 2.6 2.5 3.8 Total CH 4 - stationary combustion 0.6 0.7 0.7 Total N 2 O - stationary combustion 8.1 10.0 9.0*********E.O. 12866 Review**

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Page **46** of **208** emissions for N 2 O and CH 4 from fossil - fuel - fired EGUs (9.0 and 0.7 Tg of CO 2 equivalent, respectively) is about 0.4 percent of total CO 2 equivalent emissions from fossil - fuel - fired electric power generating units. We are requesting comment on this approach and on the need to collect additional data on N 2 O and CH 4 emissions from these affected
sources. D. Litigation Directly Leading to this Rule As discussed below, in section II.E., on February 27, 2006, the EPA published a final rule that revised the standards of performance for conventional pollutant emissions of EGUs included in the Da category. ” Standards of Performance for Electric Util ity Steam Generating Units, Industrial - Commercial - Institutional Steam Generating Units, and Small Industrial - Commercial - Institutional Steam Generating Units, ” 71 FR 9866 (Feb. 27, 2006) (the “2006 Final Rule”) . The 2006 Final Rule did not establish standards of performance for GHG emissions. Two groups of petitioners filed petitions for judicial review of this rule in the U . S . Cour t of Appeals for the District of Columbia Circuit (the Court), contending,
among other things , that the rule was required to include standards of performance for GHG emissions from EGUs. The two groups of petitioners were (1) the State s of New York, California, Connecticut, Delaware, Maine, New Mexico, Oregon, Rhode Island,*********E.O. 12866 Review**

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Page **47** of **208** Vermont, and Washington, the Commo nwealth of Massachusetts, the District of Columbia, and the City of New York (collectively ‘‘ State Petitioners’’) ; and (2) Natural Resources Defense Council, Sierra Club, and Environmental Defense Fund (collectively ‘‘Environmental Petitioners’’). The po rtions of State and Environmental Petitioners’ petitions for review of the 2006 Final Rule that related to GHG emissions were severed from other petitions for review of that rule, and were formerly pending before the Court under the caption State of New Yo rk, et al. v. EPA, No. 06

– 1322. Following the U.S. Supreme Court’s decision in Massachusetts , discussed above, the Court, upon motion from the EPA, remanded the 2006 Final Rule for further consideration of the issues related to GHG emissions in light of Ma ssachusetts. The EPA did not act on that remand. To avoid further litigation, the State and Environmental Petitioners and the EPA negotiated a proposed settlement agreement that set deadlines for the EPA to propose and take final action on (1) a rule under CAA section 111(b) that includes standards of performance for GHGs for new and modified EGUs that are subject to 40 CFR part 60, subpart Da; and (2) a rule under CAA section 111(d) that includes emission guidelines for GHGs from existing EGUs that would have been subject to 40 CFR part 60, subpart Da if they were new sources. Pursuant to CAA section 113(g), the EPA*********E.O. 12866 Review**

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Page **48** of **208** published notice of the proposed settlement agreement in the Federal Register, and provided for a public comment period. 75 FR 82392 (December 30, 2010). 32 The EPA considered the comments received and concluded that they did not disclose facts or considerations indicating that the proposed settlement agreement was inappropriate, improper, inadequate or inconsistent with the CAA. Therefore, the EPA concluded that the proposed settlement agreement should be finalized. E. Coordination with Other Rulemakings E lectric utility generating units are the subject of several CAA rulemakings that have been recently completed. The EPA recognizes that it is important that all of these efforts achieve their intended environmental objectives in a common sense manner. The confluence of these rulemakings allow s the industry to look across the regulatory requirements and design cost effective integrated compliance strategies . 1. Summary of Recent and Ongoing Rulemakings Affecting this Source Category On July 6, 2011, the EPA finalized the Cross - State Air Pollution Rule ( CSAPR ). 76 FR 48208 ( August 8, 2011 ) . The CSAPR requires 27 states and the District of Columbia to improve air quality by reducing power plant emissions that contribute to ozone and fine
32 Copies of the Federal Register notice, the settlement agreement, other supporting documents and the comments received are available online at fdms.gov under docket EPA- HQ - 2010 - 1057.*********E.O. 12866 Review**

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Page **49** of **208** particle pollution in other states. On July 6, 2011, the EPA also issued a supplemental proposal that requires six states to make summertime NOX reductions under CSAPR’s ozone - season control program . The CSAPR covers five of these six states. The CSAPR and the supplemental proposal apply to 3,642 EGUs at 1,081 coal - , gas - and oil - fired facilities in 28 states. Emission reductions will take effect quickly, starting January 1, 2012 for SO 2 and annual NOX reductions, and May 1, 2012 for ozone season NOX reductions. By 2014, combined with other final state and EPA actions, the CSAPR will reduce power plant SO 2 emissions by 73 percent and NOX emissions by 54 percent from 2005 levels in the CSAPR region. On March 16 , 2011, the EPA proposed the Mercury and Air Toxic Standards (MATS) rule to reduce emissions of mercury and other HAP emissions from coal and oil - fired power plants. This regulation , which the EPA expects to final ize later this year, will require investments in pollution controls to reduce emissions of mercury, other metals and acid gases by 2015 or 2016. In the same notice as the MATS rule, EPA proposed to revise the NSPS for criteri a pollutants from these sources and expects to finalize at the same time as the MATS rule . Because the control technologies and strategies that reduce SO 2 and to a lesser extent NOX , can also reduce or help to reduce HAP emissions , coordinating compliance strategies*********E.O. 12866 Review**

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Page **50** of **208** for the CSAPR and MATS rules , including the revised NSPS for criteria pollutants, will allow cos t - effective compliance options.

In April, 2011, the EPA proposed standards under the C lean Water Act (CWA) to reduce injury and death of fish and other aquatic life caused by cooling water intake structures existing at power plants and factories . 76 FR 22174 (April 20, 2011). These facilities pull in large volumes of cooling water from lakes, rivers, estuaries or oceans to cool their machinery. By setting flexible technology standards, the EPA’s common sense proposal would greatly reduce damage to ecosystems while accommodating site - specific circumstances and pr oviding cost effective options. The EPA recognizes that it is important that each of these efforts achieve s its intended environmental objectives in a c ommon sense manner that allows the industry to comply with all of its obligations under these rules as efficiently as possible and to do so by making coordinated investment decisions and, to the greatest extent possible, by adopting integrated compliance strategies. In addition, EO 13563 states that ‘‘[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote ... coordination, s implificatio n, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve*********E.O. 12866 Review**

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Page **51** of **208** regulatory goals that are designed to promote innovation.’’ Thus, the EPA recognizes that it needs to approach these rulemakings, to the extent that its legal c onstraints permit, in ways that allow the industry to make practical investment decisions that minimize costs in c omplying with all of the final rules, while still achieving the fundamentally important environmental and public health benefits that the rulemakings must achieve. **2. PSD and Title V Implications** Commenters have asked whether the rulemaking the EPA is proposing today has implications for EGUs and other stationary sources under the PSD and Title V programs. We discuss this issue in section VI , below, and we include relevant background information in that discussion. **3. Stakeholder Input** The EPA has been engaged in extensive interactions with many different stakeholders on the subjects of climate change, source contributions, and potential emission reduction opportunities. These stakeholders have included industries, environmental organizations, and many regional, State, and local air quality management agencies that have been actively engaged in efforts to address GHG emissions
over a perio d of several years. In addition to these conversations, as part of developing this proposed rule , the EPA held five listening*********E.O. 12866 Review**

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Page **52** of **208** sessions in February and March 2011 to obtain additional information and input from key stakeholders and the public. Each of the f ive sessions had a particular target audience: the electric power industry, environmental and environmental justice organizations, state s and Tribes, coalition groups, and the petroleum refinery industry. Each session last ed two hours and featured a facili tated round table discussion among stakeholder representatives who were identified and selected for their expertise in the CAA standardsetting process. The EPA had asked key stakeholder groups to identify these round table participants. The EPA accepted c omments from the public at the end of each session and via the electronic docket system. From the listening sessions and written submissions, the EPA received a wide range of comments and ideas for this proposed rule . Main topics of comments , which concerned requirements for both new and existing sources, include d the following:

 Feasibility and availability of control technologies

 Output -based standards

 Subcategorization factors

 Fleet -wide averaging

 Neutrality of fuels

 Role of efficiency improvements*********E.O. 12866 Review**

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Page **53** of **208**  Equivalency of state and regional reduction programs

 Recognition of early action by industries and state s achieving reductions

 Use of a multi -pollutant, multi -media approach

 Market -based flexibility

 Use of a tiered structure, with requirements evolving ove r time

 Credit for replacement of older, less efficient generation units

 Role of biomass

 Consideration of compliance issues arising from conflicts with other regulatory programs

 Schedule for proposing and promulgating this rule

 Small business impacts Comme nts submitted via the electronic docket system concerning development of this proposed rule are available at
www. regulations.gov (docket number EPA- HQ - OAR- 2011 - 0090). **III. Proposed Requirements for New S** **ources** This section describes the proposed requirements i n this rulemaking for new sources . Our rationale for the se proposed requirements is provided in Section IV of this preamble. A. What is the affected source? Sources affected by today’s proposal for new source provisions are sources that are c onsidered both covered EGUs as defined by this*********E.O. 12866 Review**

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Page **54** of **208** rule and “new” sources as defined under the provisions of CAA section 111 . 1. Covered EGUs, Generally The EPA is proposing to define a covered EGU , which is a source that is subject to this rule, as any fossil - fuel - fired combustion unit that supplies more than one - third of its potential annual electric output and more than 25 MW net - electrical output to any utility power distribution system for sale, with certain exceptions noted below. For this proposed rule, covered EGU s include electric utility steam generating units (“boilers”), combined cycle combustion turbines and their associated heat recovery steam generators ( HRSG ) and duct burners ; and IGCC units , including their combustion turbines and associat ed HRSG. However, for purposes of this rule, covered EGUs do not include simple cycle combustion turbines. In addition, units subject to emission requirements under CAA section 129 would not be subject to requirements under this proposed rule. 2. CO 2 Emiss ions Only This action proposes to regulate covered EGU emissions of CO 2 , and not other constituent gases of the air pollutant GHG, although we identify the pollutant we propose to regulate as GHGs . Note that
emissions of criteria pollutants for covered EGU s remain covered under 40 CFR part 60 subparts Da and KKKK.*********E.O. 12866 Review**

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Page **55** of **208** 3. “New” sources CAA section 111(a)(2) defines a “new source” as “any stationary source, the construction or modification of which is commenced after publication of regulations (or, if early, proposed regulations) prescribing a standard of performance under [CAA section 111] which will be applicable to such source.” In contrast, CAA section 111(a)(6) defines an “existing source” as “any stationary source other than a new source.” The definition of a “new source” applies according to its terms for purposes of this rulemaking, except that special considerations come into play for sources undertaking physical or operational changes, transitional sources, and sources undertaking reconstruction, as discussed below in Section V of this preamble. B. What emissions limitations must I meet? In this rulemaking, the EPA is proposing a standard of performance (NSPS), and we are requesting comment on an alternative compliance option , for CO 2 emissions from affected sources, which are new fossil - fired EGUs described above in Section III.A, . 1. Standard of performance The standard of performance is a gross output -based CO 2 emission limit expressed in units of emissions mass per unit of useful recovered energy ( specifically, in pounds per megawatt - hour*********E.O. 12866 Review**

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Page **56** of **208** ( lb/MWh) ) . This emission limit would be effective upon the effective date of the final action. We are not proposing any subcategories for new affected sources . Instead, we are proposing a single output -based CO 2 emission limit that must be met by all affected sources . 33 Specifically, the EPA is proposing a standard of 1 , 000 lb CO 2 /MWh , but , as discussed below , is taking comment on a range from 950 lb CO 2 /MWh to 1 , 100 lb CO 2 /MWh. As discussed below, the proposed method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the electrical energy output and useful thermal energy output, where applicable for CHP EUGs, over a roll ing 12 -month period. In the alternative, we solicit comment on requiring calculation of compliance on an annual (calendar year) period . Under this proposal, n o averaging or emissions trading among affected sources wou l d be allowed. We seek comment on all aspects of the proposed standard of performance, including using net , instead of gross , generation -based emissions rate measurement. 2. Alternative compliance option We also solicit comment on an alternative compliance option that would be available only for affected sources that comply with the

33 As discussed below, we are not proposing such a limit for modifications, transitional sources, or reconstructed sources.*********E.O. 12866 Review**

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Page **57** of **208** standard through the use of CCS. This approach involves a performance standard that includes both annual emission limits and a longer - term limit that may be met on an average basis over a 30 - year period. Specifically, the affected sources would initially be required to meet a 12 -month rolling average CO 2 emissions limit based on the best demonstrated performance of a coal - fired facility without CCS , which is 1,800 lb CO 2 /MWh ( 816 kg CO 2 /MWh) ( gross ). In the alternative, EPA solicits comment on requiring compliance through an annual (calendar year) average emission limit. This proposed emission limit can be met by modern coal - fired facilities using supercritical steam conditions, IGCC facilities, and pressurized circulating fluidized bed boilers . At some time after commencing construction and beginning operations (e.g., after the first 10 years), the facility would be requ ired to meet a reduced emission limit for the remainder of the 30 - year period (e.g., the subsequent 20 years) such that the weighted average CO 2 emissions rate from the facility over the 30 - year time period would be equivalent to the proposed standard of p erformance of 1,000 lb CO 2 /MWh. This reduced emissions standard during the remainder of the 30 - year period would be met with some level of CCS. The EPA is also soliciting comment on what additional requirements would be necessary to implement the 30 - year averaging requirement. Specifically, the owners or operators of the unit could*********E.O. 12866 Review**

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Page **58** of **208** be required to submit a plan that includes a location to store CO 2 and a schedule for construction and operation of their carbon capture system. The schedule would include key milestone dates such as soliciting proposals, obtaining financing, beginning construc tion, and beginning operation. The EPA requests comment on the appropriateness of including these, and/or other requirements to ensure that the owners or operators of the facility have adequate plans in place to meet the 30 - year average emission rate requirement. Although this alternative compliance option allows for a 30 - year averaging period, the source should also be subject to shorter term compliance requirements that a re practicably enforceable to ensure that it is on a path to comply with the 30 - year average limit. The EPA believes that these shorter term compliance requirements must include specific emission limits (e.g. annual average). EPA is considering several dif ferent forms for these minimum requirements. We are requesting comment on the form of these and any other shorter term compliance requirements, including in the event we include a 30 - year average in the final rule if it should automatically terminate in 20 20 such that only facilities that commenced construction prior to 2020 would be able to use the 30 - year average. In the first option, the source would be required to submit a 30 - year emission trajectory, specifying the emission rates it intends*********E.O. 12866 Review**

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Page **59** of **208** to meet ea ch year consistent with meeting a 30 - year average emission rate of 1,000 lb CO 2 /MWh. Each of these annual emission rate requirements would be part of the unit’s enforceable permit, and therefore would be enforceable on a short - term basis. We solicit
commen t on whether the requirements should be enforceable on a rolling 12 -month basis, which is the same period as the standard of performance proposed under Section III.B.1. of this preamble. This option would give complete discretion to the source to plan the timing of emissions reductions, as long as the 30 - year average rate would be achieved. A second option would be the same requirements of the first option with the addition of certain EPA- defined minimum requirements, or progress milestones, to assure that the source reaches certain emissions levels within defined time periods. The rationale for these milestones would be to ensure earlier emissions - reducing actions and interim progress, and to reduce the risk that the source in the end fails to achieve its required 30 - year average emission rate by the end of the 30 th year. For example, by the 11th year, the unit could be required to meet at least the 1,000 lb CO 2 /MWh requirement of the standard of performance on an average annual basis. Such a requirement would have the effect of assuring that the source implements CCS by the 11 th year, but could allow the source to*********E.O. 12866 Review**

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Page **60** of **208** phase in the amount of CO 2 emissions that its CCS system captures and stores . A third option would require that this minimum 11 th year requirement must be calculated, based on the source’s performance in the first 10 years, to assure that the source will fully implement CCS by that year. For example, if the unit operated at a rate of 1,800 lb CO 2 /MWh for the first 10 years, the requirement starting in year 11 would be 600 lb CO 2 /MWh, which is the level that, if maintained by the source for the remainder of the 30 - year period, would assure the source would meet the required 30 - year average limit. Of the three options, the third opti on would provide the least discretion to sources on the timing of emissions reductions. EPA suggests that this alternative compliance option may be warranted to provide power companies with the option of building a coal - fired power plant in the near term and installing CCS at a later time when costs will likely be lower and further experience from demonstration projects will have been gained. As discussed elsewhere, the Administration’s interagency CCS task force report anticipates that CCS will become wide ly commercially available after 2020. The 30 - year averaging period is sufficiently long to allow sources, before they install CCS, to benefit from the experience that will be gained from commercial - scale CCS demonstration projects operating*********E.O. 12866 Review**

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Page **61** of **208** over the next decade. A new coal - fired unit could operate for at least a decade before installing CCS and still have enough years operating at a controlled emission rate to reach a 1,000 lb CO 2 /MWh standard on a 30 - year basis. Because the policy purpose of this alternat ive compliance option is to leave open the option of building a coal - fired unit in the near term and installing CCS after several years, a long averaging period is needed to allow time for such a unit to achieve the 1,000 lb CO 2 /MWh level. We note that under CAA section 111(b)(1)(B), “the Administrator shall, at least every 8 years, review and, if appropriate, revise [the] standards [of performance] ... ”. This review is required to take place in 2020, if not sooner. In the event that the EPA adopts the alt ernative compliance option, then at the time of the next required review , the EPA will evaluate the state of development or commercialization of CCS technologies and make a determination as to whether or not the 30 - year averaging approach is st ill warrante d for
new sources. Because we expect CCS technology to advance over the next several years, we believe that it may not be necessary to include this type of alternative compliance option for a 30 - year average the next time we review this NSPS. In light of this, we further solicit comment as to whether the alternative compliance option should automatically terminate in 2020, so that it would be*********E.O. 12866 Review**

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Page **62** of **208** available only for facilities that commenced construction prior to 2020. As with the proposed standard of performanc e, n o averaging or emissions trading among affected sources wou l d be allowed for this alternative compliance option . We seek comment on all aspects of this alternative compliance option. C. What are the startup, shutdown, and malfunction requirements? 1. Startups and shutdowns The NSPS that EPA is proposing in this action would apply at all times , including during startups and shutdowns . In establishing the level of the proposed NSPS, the EPA has taken into account startup and shutdown periods . EPA is not propos ing differe nt standards for those periods. To establish the proposed NSPS’s output -based CO 2 standard, we accounted for periods of startup and shutdown by considering periods of part - load operation. As noted above, the proposed method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the electrical energy output and useful thermal energy output, where applicable for CHP EUGs, over a rolling 12 -month period. This averaging approach gives more weight to high - load hours and more accurately reflects overall environmental performance. In addition, because low- load hours do not factor as*********E.O. 12866 Review**

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Page **63** of **208** heavily into the calculated average, the impact of including periods of startup and shutdown is minimized when c alculating emission rates. We solicit comment on the alternative of requiring compliance through an annual (calendar year) average. We propose that these same requirements for startups and shutdowns would apply to the 30 - year alternative compliance option . 2. Malfunctions Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations . By contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * * ’’(40 CFR 60.2). The EPA has determined that CAA section 111 does not require that emissions that occur during periods of malfunction be factored into development of CAA section 111 standards. Further, nothing in section 111 or in case law require s that the EPA anticipate and account f or the innumerable types of potential malfunction events in setting emission standards. See, Weyerhaeuser v . Costle, 590 F.2d 1011, 1058 (DC Cir. 1978) (‘‘In the nature of things, no general limit, individual permit, or even any upset provision can anticip ate all upset situations. After a certain point, the transgression of regulatory limits caused by*********E.O. 12866 Review**

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Page **64** of **208** ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter f or the administrative exercise of
case -by- case enforcement discretion, not for specification in advance by regulation.”) Further, it is reasonable to interpret CAA section 111 as not requiring the EPA to account for malfunctions in setting emissions standa rds. For example, we note that section 111 provides that the EPA set standards of performance which reflect the degree of emission limitation achievable through ‘‘the application of the best system of emission reduction’’ that the EPA determines is adequately demonstrated. Applying the concept of ‘‘the application of the best system of emission reduction’’ to periods during which a source is malfunctioning presents difficulties. The ‘‘application of the best system of emission reduction’’ is more app ropriately understood to include operating units in such a way as to avoid malfunctions. Further, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the c ategory 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”*********E.O. 12866 Review**

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Page **65** of **208** foreseeable . 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 scient ific information, rather than to "invest the resources to conduct the perfect study." ). In addition, the goal of a best controlled or best performing source is to operate in such a way as to avoid malfunctions of the source and accounting for malfunctions could lead to standards that are significantly less stringent than levels that are achieved by a well -performing non -malfunctioning source. The EPA’s approach to malfunctions is consistent with section 111 and is a reasonable interpretation of the statute. In the event that a source fails to comply with the applicable CAA section 11 1 standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emi ssions 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 failure to comply with the CAA section 11 1 standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused*********E.O. 12866 Review**

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Page **66** of **208** in part by poor maintenance or careless operation.” 40 CFR section 6 0 .2 (definition of malfunction). Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause an exceedance of the relevant emission standard. ( See, e.g., “ State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and S hutdown ” (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983) , which are both included in the docket for this rulemaking. ) The EPA is therefore proposing to add to the final rule an affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions. See 40 CFR 6 0 . 10042 (defining “affirmative defense” to mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, re garding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.). We also a re proposing other regulatory provisions to specify the elements that are neces sary to establish this affirmative defense : the source must prove by a preponderance of the evidence that it has met all of the elements set forth in 6 0 . 10001 . (See 40 CFR 22.24). The criteria ensure that the affirmative defense is available only*********E.O. 12866 Review**

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Page **67** of **208** where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 6 0 .2 (sudden, infrequent, not reasonabl y preventable and not caused by poor maintenance and or careless operation). For example, to successfully
ass ert the affirmative defense, the source must prove by a preponderance of the evidence that excess emissions “[w]ere caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process t o operate in a normal or usual manner....” The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance with section 6 0 . 10001 and to prevent future malfunctions. For example, the source must pr ove by a preponderance of the evidence that “[r]epairs were made as expeditiously as possible when the applicable emission limitations were being exceeded...” and that “[a]ll possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health....” In any judicial or administrative proceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met its burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with section 113 of the CAA (see also 40 CFR part 22.77).*********E.O. 12866 Review**

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Page **68** of **208** The EPA included an affirmative defense in the final rule in an attempt to balance a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission limits may be exceeded under circumstances beyond the control of the source. The EPA must establish emission standards that “limi t the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. §7602(k)(defining “emission limitation and emission standard”). See generally Sierra Club v. EPA , 551 F.3d 1019, 1021 (D.C. Cir. 2008) Thus, the EPA is required to ensure that section 112 emissions limitations are continuous. The affirmative defense for malfunction events meets this requirement by ensuring that even where there is a malfunction, the emission limitation is still enforceable through injunct ive relief. While “continuous” limitations, on the one hand, are required, there is also case law indicating that in many situations it is appropriate for the EPA to account for the practical realities of technology. For example, in Essex Chemical v. Rucke lshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that in setting standards under CAA section 111 “variant provisions” such as provisions allowing for upsets during startup, shutdown and equipment malfunction “appear necessary to preserve the reasonableness of the standards as a whole*********E.O. 12866 Review**

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Page **69** of **208** and that the record does not support the ‘never to be exceeded’ standard currently in force.” See also, Portland Cement Association v. Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973) . Though intervening case law such as Sierra Club v. EPA and the CAA 1977 amendments undermine the relevance of these cases today, they support the EPA’s view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil penalties for excess emissions that are proven to be beyond the control of the source. By incorporating an affirmative defense, the EPA has formalized its approach to upset events. In a Clean Water Act setting, the Ni nth Circuit required this type of formalized approach when regulating “upsets beyond the control of the permit holder.” Marathon Oil Co. v. EPA , 564 F.2d 1253, 1272 - 73 (9 th Cir. 1977). But see, Weyerhaeuser Co. v. Costle , 590 F.2d 1011, 1057 - 58 (D.C. Cir. 1978) (holding that an informal approach is adequate). The affirmative defense provisions give the EPA the flexibility to both ensure that its emission limitations are “continuous” as required by 42 U.S.C. §7602(k), and account for unplanned upsets and thu s support the reasonableness of the standard as a whole. We propose that these same requirements for malfunctions would apply to the 30 - year alternative compliance option. D. What are the continuous monitoring requirements?*********E.O. 12866 Review**

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Page **70** of **208** The EPA is propos ing that a CO 2 mass rate CEMS and the associated automatic data acquisition and handling system must be install ed and operate d in accordance with the requirements below. 1. Prepare a site - specific monitoring plan that addresses the monitoring system design, data collection, and the quality assurance and quality control elements consistent with the requirements in 40 CFR part 75. a. Use all the data collected during all other required data collection periods in assessing the operation of the control device and associated control system. b. Report any periods for which the monitoring system failed to collect required data. c. Except for periods of monitoring system malfunc tions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments); failure to collect required data is a deviation of the monitoring requirements. 3. We propose that owners/operators would install the CEMS and complete the CEMS certification in accordance with the schedule required in 40 CFR part 75, section 75.4(b).*********E.O. 12866 Review**

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Page **71** of **208** We also request comment on the appropriateness of applying the backup monitor requirements in 40 CFR part 75.10(e), the missing data procedures in 40 CFR part 75, sections 75.31 through 75.37, and
appendix C for this proposed rule. We propose that these same monitoring requirements would apply to the 30 - year alternative compliance option. E. What are the emissions performance testing requirements? Consistent with the performance testing requirements in the CAA section 111 regulatory general provisions (40 CFR part 60.8) and CEMS certif ication requirements (40 CFR part 75.4(b)), we propose that owners/operators of a new unit, conduct an initial performance test to demonstrate compliance with the CO 2 emissions limits beginning in the calendar month following initial certification of the CO 2 and flow rate monitoring CEMS. We propose that the initial performance test consist of collection of hourly CO 2 average concentration, mass flow rate ( standard cubic feet per hour ) recorded with the certified CO 2 concentration and flow rate CEMS and the corresponding electrical power generation data for all of the hours of operation for the first calendar year beginning on the first day of the first month following completion of the CEMS installation and certification. For all of the operating hours duri ng each monthly period, including startup and shutdown, you would*********E.O. 12866 Review**

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Page **72** of **208** calculate compliance with the emissions limit by dividing the sum of the hourly CO 2 mass values by the sum of the hourly useful energy output produced over the first 12 months of data. We pr opose that these same emissions performance testing requirements would apply to the 30 - year alternative compliance option. F. What are the continuous compliance requirements? In this rulemaking, we propos e that compliance with the applicable average CO 2 mass emissions rate (lb/MWh) must be calculated as a 12 -month rolling average, updated monthly, using the reported hourly CO 2 average concentration and flow rate values from the certified CEMS data collected for the previous month’s process operating days along with generation data tracked by the facility for the unit. We propose that compliance with the emissions limit must be calculated by dividing the sum of the hourly CO 2 mass emissions values by the sum of the useful energy output produced for each ca lendar month period and that the 12 -month rolling average must be updated as the average of the previous 12 months ’ calculations. Affected sources will continue to be subject to the standards and maintenance requirements in the section 111 regulatory gener al provisions . 40 CFR part 60, subpart A. We solicit comment on, in the alternative, an annual (calendar*********E.O. 12866 Review**

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Page **73** of **208** year) average emission limit , which would be calculated through comparable methodology as just described. We propose that these same continuous compliance requirements would apply to the 30 - year alternative compliance option. G. What are the notification, recordkeeping, and reporting requirements? In this rulemaking, the EPA is proposing that you , as the owner or operator of a new unit, must comply with the notification and recordkeeping requirements in the section 111 regulatory general provisions, 40 CFR part 60, subpart A, and need to report results of performance testing and excess emissions ; as well as record and maintain hourly average CO 2 emissions concentration, hourly average flow rate, and hourly useful electrical generation. Note that the summary form identified as Figure 1 in 40 CFR part 60.7(d) will be revised to include CO 2 as a pollutant. We are aware that owners or operators of many existing EGUs are required to submit emissions data through the EPA Acid Rain Program’s Emissions Collection and Monitoring Plan System ( ECMPS ) for SO 2 , NOx , CO 2 , and other related data. We propose for affected sources to continue to use ECMPS with modifications to allow for collecting CO 2 mass emissions data and the CEMS relative accuracy reports proposed in this rule.*********E.O. 12866 Review**

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Page **74** of **208** We request comment on these and other modifications to ECMPS appropriate for implementing this rule and any other EPA rules that apply to EGUs in order to streamline and focus all applicable emissions data reporting requirements. We request comment on modification of the ECMPS system to collect, track, and calculate CO 2 emissions rates based on hourly useful energy output for the unit. We also reque st comment on tracking and making use of useful steam data for new facilities. We are also aware that owners or operators of existing units are required to submit electrical generation data according to procedures required by the DOE’s Energy I nformation Administration (EIA) f or its reports. We request comment on the appropriateness of using these electrical generation data in this proposed rule . The EPA propose s that these same notice, recordkeeping, and reporting requirements would apply to the 30 - year a lternative compliance option. The EPA also requests comment on whether any alterations or additions are appropriate. For example, the EPA requests comment on a potential requirement that sources wishing to utilize the 30 - year averaging option notify the pe rmitting authority at the time that they submit their preconstruction permit application. The EPA also requests comment on whether such sources should be required to include in the notification an explanation of*********E.O. 12866 Review**

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Page **75** of **208** their compliance plan, including when CCS would be deployed, what capture rate(s) would be achieved, how the CO 2 would be sequestered, and whether the company anticipates receiving government financial assistance or other incentives for the CCS. This information would be available to the public thr ough the permitting authority. **IV. Rationale for the Proposed Standards for**  **New Sources** A. How did the EPA establish the emission limits? 1. Rationale for Combining the Subpart Da Category and a C omponent of the Subpart KKKK C ategory into a New Category for GHGs The EPA is proposing to create a new subpart in 40 CFR part 60 by combining the sources in subpart Da (the Da category ) and component s of sources in subpart KKKK (the KKKK category)

– – combined cycle unit s, but not simple cycle units -- for purpos es of promulgat ing standards of performance for emissions of GHGs from new sources. This new subpart will be numbered TTTT. At this time, the EPA is not proposing subcategories for new sources and is not combining the Da category and component s of the KKKK category for conventional pollutants. CAA section 111 provides legal authority for combining the categories into a new category . C lean Air Act section 111(b)(1)(A) provides: The Administrator shall, within 90 days after December 31,*********E.O. 12866 Review**

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Page **76** of **208** 1970, publish (and from time to time thereafter shall revise) a list of categories of stationary sources. He shall include a category of sources in such a list if in his judgment it causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. (Emphasis added.) As quoted, this provision grants to the Administrator the authority to “revise” the list of categories. Combining categories, in whole or in part, is a form of “revis[ing]” the list of categories (along with taking other actions, such as adding more categories or delisting categories) , and accordingly is authorized. It is reasonable for the EPA to combine the Da category and the combined cycle component of the KKKK category at this time for purposes of GHGs, for several related reasons. First, both types of plants (boilers and combined cycle units ) perform the same function, which is to generate electricity. It is sensible to treat as part of the same category units that generate electricity, regardless o f their design or fuel type. Second, although it is true that natural gas - fired plants are inherently less emitting than coal - fired plants, all newly constructed sources have options in selecting their design. As a*********E.O. 12866 Review**

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Page **77** of **208** result, prospective owners and operators of new sources could comply with the proposed emission standards by choosing to construct a NGCC facility. These two factors provide sufficient rationale for EPA to combine the Da category and the combined cycle component of the KKKK category for purpose s of GHGs. A third factor lends further support. C ombining the categories does not foreclose construction of new coal fired EGUs because it is feasible to control CO 2 emissions from new coal - fired units to levels typically achieved by new gas - fired units . Specifically, new natural gas - fired EUGs are inherently low emitting, and that is the source of their relatively low emissions level. New coal - fired power plants

– that is, the small number that may be expected to be built in the foreseeable future -- may install CCS control equipment (if not at the time of construction, then relatively soon thereafter) and, by doing so, achieve the same emission rate (at least over time) as a natural gas - fired EGU. As discussed below, CCS is feasible as evidenced by the f act that power companies have announced plans to incorporate CCS at seven already permitted coal - fired EGU construction projects in this country (as we discuss below in section V.B., concerning transitional sources) . Our modeling , which is based on economi c factors , forecasts no new coal fired construction through the modeling period

– until 2020

– but we*********E.O. 12866 Review**

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Page **78** of **208** realize the possibility that new coal - fired construction may occur for other reasons . As discussed below, we reasonably expect the costs of CCS to decline over time. In addition, programs exist that provide some funding for CCS through pilot or other demonstration programs. As a result, we propose to conclude that coal - fired generation with CCS is feasible, although not a least - cost generation choice. To be clear, we are not proposing that CCS does or does not qualify as the “best system of emission reduction” that “has been adequately demonstrated” (although we do solicit comment on that issue). Rather, we propose to conclude that CCS is a feasible method o f alternative compliance for coal - fired power plants to meet the proposed NSPS for new construction, and that this is one reason that it is reasonable to combine the Da category and the combined cycle component of the KKKK category for GHG emissions. In addition, combining the categories can further the emission reduction goals of section 111. It makes it possible to set standards that provide assurance that the emissions performance projected from new generating units under projected market conditions (wh ich favor new NGCC over new coal - fired generation) will be achieved even in the event that market conditions shift to favor more construction of coal - fired units than currently anticipated. On the other hand, at this time, we do not consider it*********E.O. 12866 Review**

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Page **79** of **208** appropriate to include simple cycle facilities as an affected source in the new 40 CFR part 60, subpart TTTT for GHG emissions from new facilities . The reason for this is that the function of a new simple cycle power plant is different than that of a new combined cyc le plant or coal - fired plant. Combined cycle plants and c oal - fired plants are typically designed to provide base - load or intermediate load power, while simple cycle turbines are designed to provide peaking power . Because combined cycle power plants and coa l - fired power plants both serve the same purpose and have design options to emit CO 2 at similar levels, we believe it is appropriate to combine them. Because peaking turbines operate less and because it would be much more expensive to lower their emission profile to that of a combined cycle power plant or a coal - fired plant with CCS, the EPA does not believe it is appropriate to include them in th is source category. By the same token, at this time, we do not consider it appropriate to combine the Da category and the combined cycle component of the KKKK category for any pollutants other than GHGs, that is, for conventional pollutants. This is because although coal fired EGUs have an array of control options for conventional pollutants to choose from, those controls generally do not reduce their conventional emissions to the level of conventional emissions*********E.O. 12866 Review**

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Page **80** of **208** from natural gas - fired EGUs. As a result, at this time, combining the Da and KKKK categories for purposes of non - GHG emissions could have the effect o f foreclosing new coal - fired EGUs , thereby precluding further development of CCS . 2. Endangerment and Cause - or - Contribute - Significantly Finding a. Overview . In today’s rulemaking, we propose or solicit comment on alternative interpretations for whether section 111 includes prerequisites to rulemaking that involve an endangerment finding and
a cause - or - contribute - significantly finding. By its terms, CAA secti on 111 provides that once the EPA lists a source category for regulation because the category causes or contributes significantly to air pollution that may reasonably be anticipated to endanger public health or welfare, the EPA then establishes requirement s for new sources in that source category. The EPA proposes to interpret these provisions so that it is authorized to promulgate the rulemaking proposed today because it has already determined that both the Da and KKKK source categories cause or contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. The EPA solicits comment on interpreting CAA section 111 in the alternative so as to require (i) an endangerment finding for air pollution not specific ally covered by the endangerment finding the EPA made when listing the source*********E.O. 12866 Review**

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Page **81** of **208** category, but that in this case, the EPA’s 2009 Endangerment Finding for GHGs under Section 202(a) of the CAA (along with the EPA’s 2010 denial of petitions to reconsider (2010 Reconsideration Denial)), fulfills that requirement; and (ii) a cause - or - contribute significantly finding for air pollutants not specifically covered by the cause - or - contribute - significantly finding the EPA made when listing the source category, and that in this case, the large amounts of CO 2 emissions from power plants provide a compelling basis allowing the EPA to propose that finding. The EPA also solicits comment on another alternative, which is interpreting CAA section 111 so as to require the EPA to establish a rational basis for regulating an air pollutant from a source category. In this case, EPA’s 2009 Endangerment Finding for GHGs and the 2010 denial of petitions to reconsider the Endangerment Finding, as well as the large amounts of CO 2 emissions from power plants, provide that rational basis. Finally,
a s an alternative for the basis for a rational basis determination, the 2010 and 2011 Assessment Reports from the National Academies confirm the Endangerment Finding and the denial of petitions to
reconsider. b. Proposal : Previous Source Category Findings Meet Any Endangerment P rerequisite to Regulation . In this rulemaking, the EPA proposes to interpret CAA section 111 so that we are not required, as a*********E.O. 12866 Review**

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Page **82** of **208** prerequisite to regulating CO 2 emissions from EGUs, to issue a new finding as to the health or welfare impacts of GHG air pollution or a finding as to the extent that affected sources contribute to that air pollution. C lean Air Act section 111 (b)(1)(A) , by its terms, requires that the Administrator lis t a source category for regulation if the “category ... in [the Administrator’s] judgment, ... caus es or contribute s significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.” C lean Air Act section 111(b)(1)(B) goes on to provide that after listing the source category, the EPA must promulgate regulations “establishing federal standards of performance for new sources within such category.” In turn, CAA section 111(a)(1) defines a “standard of performance” as a “standard for emissions of air pollutants which reflects the degree of emission reduction which (taking into account ... cost ... and any nonair quality health and environmental impact and energy requirements) ... has been adequately demonstrated.” Thus, although CAA section 111 clearly requires the EPA to list a source category if its emissions contribute significantly to air pollution that endangers public health or welfare, and then to promulgate standards of performance for particular pollutants, section 111 do es not by its terms require that the EPA make any*********E.O. 12866 Review**

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Page **83** of **208** endangerment finding with respect to those particular pollutants , or any cause - or - contribute - significantly finding with respect to the source category , at the time EPA promulgat es the standards of performan ce for those pollutants . The lack of any such requirement contrasts with (i) the definition of “standard of performance , ” which specifically require s the EPA to consider “ nonair quality health and environmental impact,” CAA section 111(a)(1) (emphasis added); and (ii) other CAA provisions that do require the EPA to make endangerment and cause - or - contribute findings for the particular pollutant that the EPA regulates under those provisions. E.g., CAA sections 202(a)(1), 211 (c)(1) , 231 (a)(2)(A) . Accordingly, under our proposal, once the EPA has listed a source category, and the EPA proceeds to regulate particular pollutants from that source category, CAA section 111 does not require that the EPA make an endangerment finding for the relevant air po llution or a cause - or - contribute - significantly finding for the relevant air pollutants from that source category . The fact that the EPA is, in this rulemaking, proposing to partially combine the Da and KKKK source categories does not alter this outcome. As noted above,
under CAA section 111(b)(1)(A), the EPA may add a source category to the list of categories only after determining that the source category “causes, or contributes significantly to, air pollution*********E.O. 12866 Review**

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Page **84** of **208** which may reasonably be anticipated to endanger public health or welfare.” The EPA has previously determined that each of the Da and KKKK categories cause s or con tributes significantly to such air pollution. Combining the Da category and some of the sources in the KKKK category does not necessitate that the EPA make a new cause - or contribute - significantly finding for the expanded Da category. This is because the EPA has already found that at least one component of the new category - – the former Da sources -- by itself causes or contributes significant ly to such air pollution. There is no reason why this expansion of the Da category to include the pre - existing Da sources plus additional sources could be considered to contribute to such air pollution to an extent that is less than the contribution from the pre - existing Da sources alone. As a result, the new category must necessarily be considered to cause or contribute significantly to such air pollution . In addition to proposing this interpretation, we also solicit comment on alternative interpretations under CAA section 111, including those described next.
c. First Alternative I nterpretation : Endangerment Finding Prerequisite. We solicit comment on an alternative interpretation under which the EPA is required, as a prerequisite to promulgating standards of performance under CAA section 111 (b) , to have issued an*********E.O. 12866 Review**

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Page **85** of **208** endangerment finding specifically for the relevant air pollution and
a cause - or - contribute - significantly finding specifically for the relevant source category and air pollutant. In particular, wha t would be the legal basis for such an interpretation? Even if CAA section 111 is interpreted to require those findings, then, in a case in which EPA did not make those findings under CAA section 111, it is the EPA’s view that the EPA would satisfy the ne ed for a CAA section 111 endangerment finding through an endangerment or comparable finding that the EPA made or that Congress adopted under any other provision of the CAA. For example, the EPA may regulate, under CAA section 111, (i) NAAQS pollutants because of the determinations the EPA made under CAA sections 108 and 109 and (ii) HAPs that Congress listed under CAA section 112(b)(1). It is the EPA’s interpretation that once an endangerment or comparable finding is made with respect to the relevant air po llution under another CAA provision, regulation under CAA section 111 of source categories that cause or contribute significantly to that same air pollution may proceed without any need for the EPA to revisit or update that endangerment finding as part of the CAA section 111 regulatory process. Instead, any concerns about the continued validity of that endangerment finding may be resolved through a*********E.O. 12866 Review**

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Page **86** of **208** petition to reconsider that finding under the applicable CAA provision. Applying this alternative interpretati on of CAA section 111 to this rulemaking, the 2009 Endangerment Finding for GHG air pollution fulfills any requirement under CAA section 111 that the EPA issue a finding that GHG air pollution may reasonably be anticipated to endanger public health or welf are in order for EPA to establish standards of performance for GHG emissions from EGUs. As discussed above, the EPA already issued this endangerment finding under CAA section 202(a)(1), as part of its process for promulgating the Light Duty Vehicle Rule. The EPA recognizes that under this alternative interpretation, the EPA could be required to issue 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 sectio n 111. Therefore, under this alternative interpretation, in today’s rulemaking, the EPA proposes to find that CO 2 emissions from fossil fuel - fired EGUs cause or contribute significantly to the GHG air pollution. The EPA’ s basis for this proposed finding is , in part, that the large amounts of CO 2 emitted by fossil - fuel - fired EGUs clearly exceed the low hurdle necessary for the cause - or - contribute significantly finding. As noted above in Tables 2 and 3 , fossil - fuel*********E.O. 12866 Review**

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Page **87** of **208** fired EGUs emit almost one - third of all U.S. GHG emissions, and constitute by far the largest single stationary source category of GHG emissions. Indeed, so great is the contribution of CO 2 air pollutants from EGUs to GHG air pollution, that it is simply not necessary in this rulemaking to determine thresholds for when a contribution may be considered to be a “significant[]” contribution. If it were necessary, the EPA proposes that a limited amount of contribution would meet that standard in light of the fact that GHG air pollution is caused by a large number of types of sources and that no one source category domina tes the entire inventory . d. Second alternative interpretation: Rational Basis Prerequisite. As a second alternative interpretation , the lack of any requirement in CAA section 111 addressi ng whether and how the EPA is to evaluate emissions of particular pollutants from sources in the listed source category as a prerequisite for regulation may be viewed as a statutory gap that requires a Chevron step 2 interpretation. In this case, the EPA is authorized to develop an interpretation that reasonably effectuates the purposes of CAA section 111. Under this alternative interpretation, the EPA must demonstrate a rational basis for controlling the emissions of the particular pollutants. That
ra tional basis may consist of some type of factual showing that is consi stent with the purposes of CAA section 111, but may be something*********E.O. 12866 Review**

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Page **88** of **208** short of an endangerment and a cause - or - contribute - significantly finding. There are several options for the factual showings that comprise
a rational basis. Under the first option, the EPA would be justified in the present case in taking action with respect to GHG air pollution because of the EPA’s 2009 Endangerment Finding that GHG air pollution may reasonably be anticipa ted to endanger public health and welfare. The EPA issued that Endangerment Finding quite recently, in December, 2009, and by notice dated August 13, 2010, the EPA denied ten petitions to reconsider that Finding, an action that entailed further review of s cientific information. Under the second option, the EPA could conclude that the recent Endangerment Finding and denial of reconsideration, coupled with the even more recent assessments from the NAS, published in 2010 and 2011, which lend further credence to the science supporting the Endangerment Finding, suffice to provide a rational basis for promulgating regulations under CAA section 111 designed to address contributions to the GHG air pollution. Under either of these options, the EPA would need to est ablish a rational basis for regulating CO 2 emissions from affected EGUs. The fact that affected EGUs emit almost one - third of all U.S. GHGs and comprise by far the largest stationary source category of GHG*********E.O. 12866 Review**

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Page **89** of **208** emissions , as discussed above, would readily provi de such a rational basis. 3. Rationale for Emission Limits A . Few New Coal - fired Power Plants. An important part of the basis for the EPA’s proposal for new sources in this rulemaking is that all indications suggest that very few new coal - fired power plan ts 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 kinds of power plants at present and is not expected to do so for the time being . The reas ons include the current economic environment, which has lead to lower electric ity demand ; and competitive natural gas prices. Natural gas prices have stabilized over the past few years as new drilling techniques have brought additional supply to the marketplace. As a result, natural gas prices are expected to be competitive for the foreseeable future and utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. At present, the cost of generation from a new NGCC power plant is lower than the cost of generation from a new coal - fired power plant. 34 Other drivers that may influence decisions to build new power plants are State and Federal energy and tax polic ies . Many states

34 Levelized Cost of New Generation in the Annual Energy Outlook 2011 http://205.254.135.24/oiaf/aeo/electricity_gener ation.html*********E.O. 12866 Review**

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Page **90** of **208** have adopted renewable portfolio standards ( RPS ) , which require that a certain portion of electric ity come from renewable energy sources like solar or wind. The federal government has also adopted incentives for electric generation from renewable energy sources and loan guarantees for new nuclear power plants. These economic, cost, and policy factors create an environment in which natural gas - fired p ower plants, renewable energy, and nuclear power are the forms of energy generation that are most often predicted to be built to meet new electricity demand over the coming years . Various energy sector modeling efforts, including projections from both the EIA and the EPA, show results that are consistent with these findings. The Annual Energy Outlook (AEO) for 2011 shows a very modest amount of new coal - fired power coming online beyond 2012, although there are a number of coal - fired power plants that are currently under construction and expected to begin operation in the next year or two. According to the AEO 2011, the maj ority of new generating capacity will be either natural gas - fired or renewable, with some lesser amounts of nuclear power. The AEO 2011 is based on existing policy and regulations , such as state RPS programs and Federal tax credits for renewables. 35 The new generation that EIA does

35 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm*********E.O. 12866 Review**

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Page **91** of **208** shows coming on - line after 2012 fits into one of three categories. It is generation that is currently under construction, generation that will include CCS or industrial CHP. Units in the first group would not be subject t o this rule because, since they have commenced construction, they are considered existing sources. Units in the second group would include either units in the transitional category or new units. In either case, they could be built consistent with this ac tion. Units in the third group would not be subject to this rule because CHP units that generate primarily on - site power are not considered EGUs and are thus not affected by the rule. The EPA modeling using the Integrated Planning Model (IPM) , a detaile d power sector model that the EPA uses to support power sector regulations, is keyed to the AEO in a number of respects and shows similar patterns of little future construction of new coal - fired power plants under the base case. 36 The EPA’s projections from IPM can be found in the RIA. As discussed below, the fact that the expected number of coal fired power plants is so limited supports both (i) basing the standard of performance on NGCC, which is expected to be the most commonly built new fossil - fuel - fired generating technology , and (ii) treating CCS as a alternative compliance option for coal - fired power

36 http://www.epa.gov/airmarkets/progsregs/epa
ipm/BaseCasev410.html#documentation*********E.O. 12866 Review**

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Page **92** of **208** plants because it would be feasible for the few such plants that may be constructed to employ CCS, often with assistance of the demonstration programs or other incentives available for CCS. b. Basis for the Proposed Standard of Performance. In this section, we describe our basis for proposing a standard of 1,000 lb/MWh, and for taking comment on a range of 950 to 1,100 lb /MWh ( 43 0 to 50 0 kg /MWh) . We first describe our method for calculating these levels of CO 2 emissions, and then note that several states are already requiring these levels of CO 2 emissions. (1) Calculation of the S tandard. For reasons explained below (see “d. Legal Justification for the Standa rd of Performance and Alternative Compliance Option”) , a NGCC facility is the best system of emission reduction for new base - load and intermediate - load EGUs. To establish an appropriate , natural gas -based standard , we used design performance specificati ons from Gas Turbine World37 and adjusted those values to account for operation at non - design ambient temperatures, the use of post - combustion controls, normal degradation of combustion turbine components, and operation at part load , all of which reduce turbine performance .

37 Gas Turbine World is an industry periodical that provides information concerning size, performance specifications, and other characteristics for gas turbines. Information was obtained from the ‘2011 Performance Specs, 27 th Edition’.*********E.O. 12866 Review**

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Page **93** of **208** Specifically, the impact of temperature on the efficiency of combined cycle power plants is relatively minor, and we increased the design heat rate (which is a measure of overall efficiency, calculated by the amount of Btu needed to gene rate a kilowatt hour of energy) by 1 percent to account for operations at other than design conditions. The impact of post - combustion controls (i.e., selective catalytic reduction) on efficiency is also relatively minor. To account for the increased pressu re drop from the catalyst we increased the design heat rate by 25 Btu/ kWh. Degradation is a more important factor as the heat rate of the facility will gradually deteriorate between overhauls. Although generally estimated at less than 3 percent over the life of the facility, we conservatively estimated a 5 percent increase in heat rate due to degradation to account for adverse conditions and different turbine designs. Operational load is one of the primary factors in the actual operating efficie ncy and CO 2 emissions rate of a combined cycle power plant. Combined cycle power plants are most efficient when operating at full load. At 80 percent load, the actual heat rate only increases by appr oximately 1 percent relative to the design basis heat rat e. However, below 80 percent load , the heat rate begins to increase at a more significant pace. At 60 percent load, the actual heat rate increases by approximately 10 percent above the design rate.*********E.O. 12866 Review**

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Page **94** of **208** Even though most combined cycle power plants are intended to operate at high loads, part - load operation is inevitable with variable demand. We selected a 5 percent heat rate increase relative to the design rate to account for part - load conditions. The overall impact of the se adjustments increases the expected
annual operating heat rate to 11 percent above the design heat rate plus 25 Btu/kWh. Based on these assumptions, the range of operating emission rates for the eighty- one facilities listed in Gas Turbine World is 800 to 1,040 lb /MWh /MWh (37 0 kg CO 2 /MWh to 47 0 kg CO 2 ). Ninety- five percent of the se available new combined cycle designs (that is, the 81 facilities mentioned earlier) could reasonably be expected to achieve an emissions rate of 1,000 lb /MWh ( 460 kg CO 2 /MWh) over the life of the facility, and we therefore selected that as our proposed standard. This proposed standard would only limit the use of available combined cycle facilities with relatively inefficient HRSG designs. Similar designs using the same
combustion turbine engine with a more efficient HRSG would be able to comply with the standard. As such, selection of combustion turbine engine designs would not be affected by this standard. By only limiting the use of less efficient HRSGs, the proposed standard would still provide options across the full spectrum of electric generation sizes of combined cycle facilities.*********E.O. 12866 Review**

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Page **95** of **208** We are requesting comment on a range of 950 to 1,100 lb /MWh (43 0 to 50 0 kg /MWh) for the final rule. The upper limit would incorporate
ess entially all available new combined cycle designs and would have limited impact on improving efficiency of combined cycle facilities. This upper limit would also be consistent with standards promulgated by some states, as noted elsewhere. The stricter standard would in general eliminate designs without a steam reheat cycle and similar lower efficiency designs for use in electric - only generation, and
c ould limit presently available options for generation below approximately 40 MW. However, an owner/operator of combined cycle facilities with higher heat rates could either implement combined heat and power (CHP) or integrated solar thermal for feedwater heating to achieve the proposed standard. (2) States Implementing a C omparable S tandard . S everal state s have recently established emission performance standards or other measures to limit emissions of GHGs from new EGUs that are comparable to the proposal in this rulemaking . For example, i n September 2006, California Governor Schwarzenegger signed into law S enat e B ill 1368. The law limits long - term investments in baseload 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*********E.O. 12866 Review**

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Page **96** of **208** designed regulations that establish a standard for baseload 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 sign ed Substitute Senate Bill 6001 , which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any baseload electric generation that commenced operation after June 1, 2008 and is located in Washington, whether or not that generation serves load located within the st ate . Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO 2 /MWh. In July 2009, Oregon Governor Kulongoski signed S enate B ill 101 , which mandated that facilities generating baseload electricity, whether gas - or coal - fired, must have emissions equal to or less than 1,100 lb CO 2 /MWh , and prohibited utilities from entering into long term purchase agreements for baseload electricity with out - of - state facilities that do not meet that standard. Natural gas - and petroleum disti llate - fired facilities that are primarily used to serve peak demand or to integrate energy from renewable resources are specifically exempted from the performance standard. c. Basis for CCS as a Feasible Compliance Alternative . In this section, we describe the basis for our position that CCS is a feasible compliance alternative for coal - fired power plants. First,*********E.O. 12866 Review**

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Page **97** of **208** at present, CCS is technologically feasible and its core components (CO 2 capture, compression, transportation and storage) have already been implemented. Second, although the costs of CCS are presently too high for widespread deployment, we have reason to expect that the costs of CCS will decrease over time, and the Administration’s interagency CCS task force report anticipates that CCS will become widely deployable after 2020. Third, we expect construction of no more than a few new coal - fired power plants by 2020, and those may well be able to take advantage of demonstration programs or other
s ources of funding for CCS. Fourth, several states have required CCS, many projects that implement CCS or components of it are proceeding, and other projects for CCS are in the planning stages. (1) Technological Feasibility and Costs of CCS. The current sta te of affairs concerning CCS was described and analyzed by the Interagency Task Force on Carbon Capture and Storage, established by President Obama on February 3, 2010, co - chaired by the DOE and the EPA, and composed of 14 executive departments and federal agencies. The Task Force was charged with proposing a plan to overcome the barriers to the widespread, cost - effective deployment of CCS within 10 years, with a goal of bringing five to ten commercial demonstration projects online by 2016. The Task Force f ound that, although early CCS projects face economic challenges related to climate policy*********E.O. 12866 Review**

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Page **98** of **208** uncertainty, first - of - a - kind technology risks, and the current high cost of CCS relative to other technologies, there are no insurmountable technological, legal, inst itutional, regulatory or other barriers that prevent CCS from playing a role in reducing GHG emissions. The Task Force also identified the need for comprehensive review of the overall environmental impacts of CCS. (a) Capture Technologies and Costs. Capture of CO 2 from industrial gas streams has occurred since the 1930s using a variety of approaches to separate CO 2 from other gases. These processes have been used in the natural gas industry and to produce food and chemical - grade CO 2 . Although current capture technologies are feasible, the costs of CO 2 capture and compression represent the largest stumbling block to widesp read commercialization of CCS. Currently available CO 2 capture and compression processes are estimated to represent three quarters of the overall CCS costs. In general, CO 2 capture technologies applicable to coal - fired power generation can be categorized into three approaches 38 :

 Pre - combustion systems are designed to separate CO 2 and H 2 in the high -pressure syngas produced at IGCC power plants.

 Post - combustion systems are designed to separate CO 2 from the flue gas produced by fossil - fuel combustion in air.

38 IPCC, 2005; DOE, 200 7.*********E.O. 12866 Review**

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Page **99** of **208**  Oxy- combustion uses high -purity O 2 , rather than air, to combust coal and therefore produ ces a highly concentrated CO 2 stream. Each of the se three carbon capture approaches (pre - combustion, post combustion, and oxy- combustion) is technologically feasible. However, each results in increased capital and operating costs and decreased electricity output ( that is, an energy penalty), with a resulting increase in the cost of electricity. The energy penalty occurs because the CO 2 capture process uses some of the energy produced from the plant. (b) Current Availability of Transportation and Sequestrat ion . As just discussed, the primary costs associated with CCS are the costs of capturing and compressing CO 2 . The remaining steps for CCS, pipeline transportation and sequestration, are better established. C arbon dioxide has been transported via pipeline s in the U .S. for nearly 40 years. Approximately 50 million metric tons of CO 2 are transported each year through 3,600 miles of pipelines. Moreover, a review of the 500 largest CO 2 point sources in the U .S. shows that 95 percent are within 50 miles of a po ssible geologic sequestration site , 39 which would lower transportation costs. For all these reasons,

39 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, Bat telle Pacific Northwest Division. PNWD - 3602. College Park, MD.*********E.O. 12866 Review**

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Page **100** of **208** the transportation component of CCS is not expected to be a significant stumbling block to the commercial availability of CCS. With respect to sequestration , g lobally, there are at least four commercial integrated CCS facilities sequestering captured CO 2 into deep geologic formations and applying a suite of technologies to monitor and verify that the CO 2 remains sequestered. 40 These four sites represent over 25 years of cumulative experience on safely and effectively storing anthropogenic CO 2 in appropriate deep geologic formations. 41 Estimates based on DOE studies indicate that areas of the U .S. with appropriate geology have a storage potential of 1,800 billion to more than 20,000 billion metric tons of CO 2 in deep saline formations, oil and gas reservoirs and unmin e able coal seams. 42 The U . S . experience with large - scale CO 2 injection, such as at enhanced oil and gas recovery pro jects, combined with ongoing research, development , and demonstration programs throughout the world, provide confidence that the storage
– - along with capture and transport -- of large amounts of CO 2 can be achieved.

40 These projects are: Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah in Algeria, and Weyburn in Canada. 41 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. U.S. Department of Energy, Pacific Northwest National Laboratory, under Contract DE -AC05 - 76RL01830. 42 U.S. Depar tment of Energy National Energy Technology Laboratory (2010). Carbon Sequestration Atlas of the United States and Canada, Thi rd Edition.*********E.O. 12866 Review**

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Page **101** of **208** It should be noted that the EPA recently finalized two rules that aim to protect drinking water and track the amount of CO 2 that is sequestered from facilities that carry out geologic sequestration. The Underground Injection Control (UIC) Class VI rule, established under authority of the Safe Drinking Water Act, sets requirements to ensure that geologic sequestration wells are appropriately sited, constructed, tested, monitored , and closed in a manner that ensures protection of underground sources of drinking water. 43 The UIC Class VI regu lations contain monitoring requirements to protect underground sources of drinking water, including the development of a comprehensive testing and monitoring plan. This includes testing of the mechanical integrity of the injection well, ground water monit oring, and tracking of the location of the injected CO 2 using direct and indirect methods. Projects are also required to do extended post - injection monitoring and site care to track the location of the injected CO 2 and monitor subsurface pressures until it can be demonstrated that underground sources of drinking water are no longer endangered. Subpart RR of the Greenhouse Gas Reporting Program, which was established under authority of the CAA and builds on UIC requi rements, provides requirements for quantifying the amount

43 Federal Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestr ation (GS) Wells, Final Rule, 75 FR 77230 (Dec. 10, 2010).*********E.O. 12866 Review**

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Page **102** of **208** of CO 2 sequestered by these facilities. 44 In addition , the EPA recently proposed a rule that would conditionally exclude CO 2 streams from the definition of hazardous waste under RCRA , where these streams are being injected for purposes of geologic sequestration, provided that they are managed in accordance with certain conditions. 45 That proposed rule is based upon the EPA's conclusion that the management of CO 2 streams, under the proposed conditions, does not present a substantial risk to human health or the environment, and was based upon a review of existing regulatory programs applicable to the transportation of CO 2 streams, and their injection into permitted UIC Class VI wells . Together, these acti ons help create a consistent national framework to ensure the safe and effective deployment of geologic sequestration. ( 2 ) Expected reduction in CCS costs. As noted above, currently available CO 2 capture and compression processes are estimated to represent three quarters of the overall CCS costs, and it is those costs that render CCS, at present, too costly for widespread deployment. However, research is underway to reduce those costs . The DOE/National Energy Technology Laboratory ( NETL ) sponsors an extensive research development and demonstration program that is

44 Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide, Final Rule, 75 FR 75060 (Dec. 1, 2010). 45 Hazardous Waste Management System: Identification and Li sting of Hazardous Waste: Carbon Dioxide (CO 2 ) Streams in Geologic Sequestration Activities, Proposed Rule, 76 FR 48073 (Aug. 8, 2011).*********E.O. 12866 Review**

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Page **103** of **208** focused on developing advanc ed technology options that dramatically lower the cost of capturing CO 2 from fossil - fuel energy plants compared to today’s available capture technolog ies. The DOE/NETL estimates that using today’s commercially available CCS technologies would add around 80 percent to the cost of electricity for a new pulverized coal (PC) plant, and around 35 percent to the cost of electricity for a new advanced gasifica tion -based (IGCC) plant. The CCS research development and demonstration effort is aggressively pursuing efforts to reduce these costs to a less than 30 percent increase in the cost of electricity for PC power plants and a less than 10 percent increase in the cost of electricity for new gasification -based power plants. 46 The large - scale CO 2 capture demonstrations that are currently planned under DOE’s initiatives, as well as other domestic and international projects, will generate operational knowledge and en able future commercialization and widespread cost - effective 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 an d 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

46 DOE/NETL Carbon Dioxide Capture and Storage RD& D Roadmap, U.S. Department of Energy National Energy Technology Laboratory, December 2010.*********E.O. 12866 Review**

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Page **104** of **208** CO 2 capture. Most single component amine systems are not practical in a flue gas environment as the amine will rapidly degrade in the presence of oxygen and other contaminants. The Fluor Econamine FG process uses a monoethanolamine (MEA) formulation specially designed to recover CO 2 and contains a corrosion inhibitor that allows the use of le ss 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. 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 , 47 and this has

47 These studies include John M. Dutton and Annie Thomas, "Treating Progress Functions as a Managerial Opportunity," 2, 235 - 247; Dennis Epple, Linda Argote, and Rukmi ni Devadas, "Organizational Learning Curves: A Method for Investigating Intra -plant Transfer of Knowledge Acquired Through Learning by Doing," Organizational Science, Vol. 2, No. 1, February 1991; International Energy Agency, Experience Curves for Energy T echnology Policy, 2000; and Paul L. Joskow and Nancy L. Rose, "The Effects of Technological Change, Experience, and Environmental Regulation on the Construction Cost of Coal Burning Generating Units," RAND Journal of Economics, Vol. 16,Issue 1, 1 - 27,*********E.O. 12866 Review**

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Page **105** of **208** 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 ob served over the decades. We have every reason to expect that the costs of capture technology will follow this pattern. Rubin et al. used historical experience curves as the basis for estimating future cost trends for four types of new electric power plants equipped with CO 2 capture systems: PC and NGCC plants with post - combustion CO 2 capture; coal based IGCC plants with pre - combustion capture; and coal - fired oxyfuel for new PC plants. 48 They assessed the historical rates of cost reductions achieved by other energy and environmental process technologies and then, by analogy, estimated future cost reductions that might be achieved by power plants employing CO 2 capture. The results of the study suggested that total costs of CO 2 capture can be expected to reduce by the following percentages: NGCC by 40 percent, PC by 26 percent, IGCC by 13 percent, and Oxyfuel by 13 percent . In a subsequent study, the model used in the initial study was extended with learning curves for several key performance variables, including overall energy loss in p ower plants, the energy required 1985. See discussion in “The Benefits and Costs of the Clean Air Act from 1990 to 2020,” U.S. EPA, Office of Air and Radiation, April 2011. 48 Rubin, E.S.; Yeh, S.; Antes, M.; Berkenpas, M.; Davison, J.; “Use of experience curves to estimate the future cost of p ower plants with CO2 capture”, Intl. J. of Greenhouse Gas Control, 1, 188 (2007).*********E.O. 12866 Review**

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Page **106** of **208** for CO 2 capture, the CO 2 capture ratio (removal efficiency) and the power plant availability. The model predicted continued reductions in cost with increased implementation. 49 These expected reductions in CCS costs are consi stent with the Administration’s CCS task force report, which anticipates that CCS will become widely commercially available after 2020. ( 3 ) Limited amount of construction of coal - fired power plants; opportunities for CCS funding. A third reason that supports CCS as an alternative compliance option is that through the IPM model period of up to 2020, we expect few if any new builds of coal - fired EGUs. We also expect some opportunity for financial support for CCS at least through Federal demonstration programs. Accordingly, the few new coal - fired generation projects that may occur may well find that financial support for CCS is available. (4) State Requirements for CCS; Projects and Permits for CCS. Several states have recently estab lished requirements for CCS, and many projects have implemented CCS or have been permitted to do so. In May 2007, Montana Governor Schweitzer signed House B ill 25, adopting a CO 2 emissions performance standard for electric generating units in the state . House B ill 25 prohibits the state Public Utility

49 Van den Broek, M.; Hoefnagels, R.; Rubin, E.; Turkenburg, W.; Faaij, A.; “Effects of technological learning on future cost and performance of power plants with CO 2 capture” , Progress in Energy and Combustion Science 35 (2009) 457 - 480.*********E.O. 12866 Review**

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Page **107** of **208** Commission from approving new electric generating units 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 S enate B ill 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. The following is a brief summary of currently operating or p lanned CO 2 capture systems , including, in some cases, part of the components for coal -based power plant applications. AES’s coal - fired Warrior Run (Cumberland, MD ) and Shady Point (Panama, OK ) power plants are equipped with amine scrubbers developed by ABB /Lummus. They were designed to process a relatively small percentage of each plant’s flue gas. At Warrior Run, approximately 110,000 tonnes of CO 2 per year are captured, whereas at Shady Point 66,000 tonnes of CO 2 per year are captured. The CO 2 from both p lants*********E.O. 12866 Review**

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Page **108** of **208** is subsequently used in the food processing industry50
. At the Searles Valley Minerals soda ash plant in Trona, CA , approximately 270,000 tonnes of CO 2 per year are captured from the flue gas of a coal power plant via amine scrubbing and used for the carbonation of brine in the process of producing soda ash . 51 A pre - combustion Rectisol® system is used for CO 2 capture at the Dakota Gasification C ompany’s s ynthetic natural gas production plant located in North Dakota, which is designed to remove approximately 1.6 million tonnes of CO 2 per year from the synthesis gas. The CO 2 is purified, transported via a 200 -mile pipeline, and injected into the Weyburn oilf ield in Saskatchewan, Canada. In September 2009, American Electric Power Co . ( AEP ) began a pilot - scale CCS demonstration at i t s Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a 1,300 MWe coal - fired unit that was retrofitted with Alstom’s pat ented chilled ammonia CO 2 capture technology on a 20 MWe portion, or “slipstream”, of the plant’s exhaust flue gas. In May 2011, Alstom Power announced the successful operation of the chilled- ammonia CCS validation project. The AEP Alstom project, the worl d’s first facility to both capture and store CO 2 from a coal - fired power plant, represents a successful scale - up of
50 Dooley, 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. 51 IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris .*********E.O. 12866 Review**

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Page **109** of **208** ten times the size of previous field pilots (e.g., at We Energies Pleasant Prairie). The demonstration achieved capture rates from 75 percen t (design value) to as high as 90 percent , produced CO 2 at purity of greater than 99 percent , with energy penalties within a few percent of predictions. The facility reported robust steady- state operation during all modes of power plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent . AEP, with assistance from the DOE , had planned to expand the slipstream 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 project to be completed in four phases, with the system to begin commercial operation in 2015. However, in July 2011, AEP announced that it is terminating its cooperative agreement with the DOE and placing its plans to advance CO 2 capture and storage technology to commercial scale on hold, citing the current uncertain status of U.S. climate policy and the c ontinued weak economy as contributors to the decision. Oxy- combustion of coal is being demonstrated in a 10 MWe facility in Germany. The Vattenfall plant in eastern Germany*********E.O. 12866 Review**

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Page **110** of **208** (Schwarze Pumpe) has been operating since September 2008. It is designed to capture 70,000 tonnes of CO 2 per year In June 2011, Mitsubishi Heavy Industries, an equipment manufacturer , announced the successful launch of operations at a 25 MW coal - fired carbon capture facility at Southern Company's Alabama Power Plant Barry. The demonstra tion is planned to capture approximately 150,000 tons of CO 2 annually (500 tons per day) at a CO 2 capture rate of over 90 percent . The captured CO 2 will be permanently stored underground in a deep saline geologic formation. Southern Company has begun cons truction of Mississippi Power Plant Ratcliffe (formerly the Kemper County IGCC Project). Plant Ratcliffe is a 582 MW IGCC plant that will utilize local Mississippi lignite and include pre - combustion carbon capture to reduce CO 2 emissions by 65 percent . Operation is expected to begin in 2014. The CO 2 captured from Plant Ratcliffe will be used for enhanced oil recovery ( EOR ) in the Heidelberg Oil Fields in Jasper County, MS. The Texas Clean Energy Project , a 400 MW IGCC facility located near Odessa, TX wil l capture 90 percent of its CO 2 , which is approximately 3 million tonne s 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*********E.O. 12866 Review**

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Page **111** of **208** acid, a rgon, and inert slag, all of which will also be marketed. ) Construction is expected to begin in late 2011. Hydrogen Energy California, a 257 MW gasification facility in south - central California utilizing coal and petroleum coke, will capture 1.8 million to nnes per year of CO 2 using a Rectisol® process , for use in an EOR application . The facility is expected to be operational in 2016. In May 2011, SCS Energy announced that it was agreeing to take over Hydrogen Energy California and was planning to modify the project to add polygeneration capabilities. In June 2011, Alstom Power President, Philippe Joubert, discussed the results of a detailed study concerning carbon capture technology, conducted by Alstom, at the 2011 PowerGen Europe conference (Milan, Italy). The study was based on results from 13 European pilot - and demonstration - scale projects and the results were validated by independent experts. From the results of the study, Joubert concluded that “We can now be confident that carbon capture technology wo rks and is cost effective.” 52 In its recent Integrated Resource Plan, the Tennessee Valley Authority (TVA) recommended new coal additions of up to 900 MW in the 2025 - 2029 timeframe and further recommended that TVA "preserve [the]

52 June 14, 2011 press release from Alstom, “Alstom Power study demonstrates carbon capture and storage (CCS) is efficient and cost competitive”, http://www.alstom.com/power/news
- and- events/press
- releases .*********E.O. 12866 Review**

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Page **112** of **208** option of generation with c arbon capture." 53 The TVA included supercritical pulverized coal plants with CCS technology as well as IGCC plants with CCS technology as resource options in its Integrated Resource Plan evaluation . In addition, the EPA is aware of seven coal - fired EGUs for which permits have recently been issued that include CCS. As a result, these plants , if they are built, would likely be compliant with the most significant requirements of today’s proposed action. While today’s action may require some a dditional monitoring and reporting requirements, substantive changes to the design of the plants would not be necessary for compliance . d. Legal Justification for the Standa rd of Performance and Alternative Compliance Option. This section describes our legal justification for propos ing that new affected facilities in the TTTT category
– - which combine s the Da and part of the KKKK categories

– - (i) must limit their CO 2 emissions to 1,000 lb CO 2 / MWh , which an affected facility could achieve by constructing a NGCC unit or by constructing a coal - fired boiler that implements CCS immediately ; or (ii) in the case of a coal - fired power plant, may implement an alternative compliance option that allows an affected facility to meet an initial CO 2 emission limit of 1,80 0 lb CO 2 /MWh ( 816 kg

53 IRP, March 2011.*********E.O. 12866 Review**

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Page **113** of **208** CO 2 /MWh) ( gross ), and then

– - through the implementation of CCS -- meet the 1,000 lb CO 2 /MWh standard, on a time - averaged basis, over no longer than a 30 - year period. ( 1 ) Legal Justification for the Standard of Peformance. The EPA proposes that the emission limit of 1,000 lb CO 2 /MWh meets the requirements for a “standard of performance” applicable to new sources under CAA section 111(b)(1)(B). The term “standard of performance” is defined under CAA section 111(a)(1) as follows: Def initions. For purposes of this section: (1) The term “standard of performance” means 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 whi ch (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. We apply th is definition, in effect, from the bottom up. That is, first, we determine the “best system of emission reduction which (taking into account * * * cost [and other factors] ) the Administrator determines has been adequately demonstrated.” For EGUs, that is a NGCC facility, for reasons discussed be low. Then, we calculate the “degree of emission limitation achievable through the application of” such best system ; and after that, we formulate “a standard for emissions of air pollutants which reflects” that degree of emission limitation. This standard i s 1,000 lb of CO 2 / MWh. These*********E.O. 12866 Review**

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Page **114** of **208** analytical steps are also discussed further below. In determining the “best system of emission reduction” for this category of boilers and combined cycle units, we considered a range of natural gas - fired and coal - fired generati on technologies , with available controls. We considered modern supercritical and ultra supercritical coal - fired boilers. This technology is available

– - it is currently deployed in Europe and is now being widely deployed in Asia (especially China)

– - and i t offers much more efficient operation than the subcritical boilers that have more often been constructed in the U.S. These supercritical and ultra - supercritical boilers have CO 2 emissions of approximately 1,800 lb/MWh and provide the lowest overall costs for conventional coal -based electricity . We also considered new IGCC, or “coal gasification” facilities, which can have CO 2 emissions levels very similar to those of ultra supercritical coal - fired units

– – albeit at a higher price. We also considered natural gas - fired boilers which have CO 2 emissions of approximately 1,350 lb/MWh, obviously much lower than the advanced coal - fired or coal gasification technologies. However, it seems unlikely that utilities would choose a natural gas - fired boiler as the generation technology of choice when NGCC is a much more efficient, less expensive, and more widely used technology. We propose that a NGCC facility is the best system of emission*********E.O. 12866 Review**

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Page **115** of **208** reduction for two main reasons. First, natural gas is far less polluting than coal. Combustion of natural gas emits only about 50 percent of the CO 2 emissions that combustion of coal does per unit of energy generated. Second, new natural gas - fired EGUs are less costly than new coal - fired EGUs, and as a result, our IPM model proje cts that for economic reasons, natural gas - fired EGUs will be the facilities of choice until at least 20 20 , which is the model period . Indeed, those models do not project construction of any new coal fired EGUs during that period. This state of affairs ha s come about primarily because technological development and discoveries of abundant reserves have caused natural gas prices to decline precipitously in recent years and have secured those relatively low prices for the near - future. Importantly, because the IPM modeling shows that natural gas - fired plants are the facilities of choice, the proposed standard of performance in today’s rulemaking

– – which is based on the emission rate of a new NGCC unit

– – does not add costs. In addition, compared to coal - fired EGUs, natural gas - fired EGUs have less nonair quality health and environmental impacts. Essentially because natural gas is cleaner and cheaper than coal, natural gas - fired EGUs qualify as 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*********E.O. 12866 Review**

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Page **116** of **208** energy requirements) the Administrator determines has been adequately demonstrated.” We recognize that today’s proposed approach of combining the Da category and a portion of the KKKK categor y, and applying as the standard of performance the rate that natural gas - fired EGUs can meet , represents a departure from prior agency practice. We consider this departure warranted in light of both the emissions benefits and the changed economic circumstances, notably the lowered prices of natural gas due to technological development and recent discoveries that have boosted recoverable reserves. We are aware that in theory, those economic circumstances could change and if they do, then a change in the standard of performance may be warranted. In this regard, we note that CAA section 111(b)(1)(B) requires that the EPA “shall, at least every 8 years, review and, if appropriate, revise [the] standards [of performance].” This 8 - year review cycle provides a mechanism for the EPA to assure that the standard of performance for any particular source category continues to reflect the “best system.” ( 2 ) Legal Justification for the Alternative C ompliance Option. Although the IPM model projects that for economic reasons, new coal - fired EGUs will not be built in the foreseeable future, we recognize that in a few instances, owners or operators may in fact*********E.O. 12866 Review**

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Page **117** of **208** seek to build coal - fired EGUs. As discussed in detail below, under today’s proposed rulemaking, those owners or operators could avail themselves of an alternative compliance option: They could (i) achieve the supercritical efficiency level for an initial period (e.g., up to the first 10 years), and (ii) after that, implement CCS so as to achieve the 1,000 lb CO 2 / MWh rate on an average annual basis over a 30 - year period. Because CO 2 is long - lived in the atmosphere, the 30 - year averaging period is not expected to have a different impact on climate compared to a continuous emission rate limit or an annual emissions limit. The significance of th i s compliance alternative being proposed is several - fold. As a practical matter, i t offer s a vehicle for the construction of new coal - fired EGUs in those few instances in which
owners or operators decide to construct such EGUs, notwithstanding the underlying economic s . Also , i t offer s a vehicle for the continued scaling of CCS, a process that can be expected to lower the costs of CCS and thereby allow it to become more widely available in the future. In addition, th i s compliance alternative provide s further support for the reasonableness of the EPA’s proposals in this rulemaking to combine the Da category and a portion of the KKKK categor y and to determine that a NGCC facility is the “best system of emission reduction.” This is because th is compliance alternative , by*********E.O. 12866 Review**

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Page **118** of **208** providing a vehicle for new coal - fired power plant builds, would minimize any disruptions that the EPA’s proposals might, at least in theory, otherwise entail to the powe r plant industry . The compliance alternative does not achieve these goals by necessarily qualifying as the “best system of emission reduction which (taking into account cost [and other factors]) the Administrator determines has been adequately demonstrate d . ” Instead, f or the reasons discussed next , th is compliance alternative is a reasonable option, whether or not it would qualify as the “best system.” First, it is reasonable to expect that some coal - fired power plants may be able to implement CCS at the p resent time, and thereby achieve the 1,000 lb CO 2 / MWh standard immediately. As noted elsewhere, CCS has been demonstrated to be technologically achievable , and , even though it is costly, there are some state and other subsidy programs that can make CCS more affordable, particularly in tandem with use of captured CO 2 for enhanced oil recovery, and those programs may be sufficient for the very few new coal - fired plants that are expected to be constructed in the foreseeable future. Some of these programs are discussed above. Second, it is reasonable to expect that some coal - fired power plants may be able to implement the supercritical efficiency standard*********E.O. 12866 Review**

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Page **119** of **208** for an initial period of time (e.g., again, the first 10 ye ars) and then implement CCS after that, so that the source achieves the 1,000 lb CO 2 /MWh standard on average over the 30 - year period following construction. We are soliciting comment on whether this compliance alternative could be considered the “best syst em of emission reduction” and therefore whether the associated standard (the 1,000 lb CO 2 /MWh averaged over 30 years) would qualify as a “standard of performance” under CAA section 111(a)(1) . But i n any event, this proposed compliance option is reasonable. 54 Third , the EPA is authorized under CAA section 111 to anticipate that technology that is costly at present will come down in price in the future. It is clear from the legislative history of section 111 and relevant case law that the EPA may anticipate fu ture developments

– - as long as supported by an adequate record

– - in determining whether a particular system of emission reduction is the “best system ... adequately demonstrated , ” and the same should be true in determining whether a particular system of emission reduction qualifies as a reasonable alternative compliance option. The Senate Committee Report to the 1970 CAA Amendments, which first enacted CAA section 111, made clear that the EPA may anticipate future developments in determining the best syst em of emission

54 Note that under today’s proposed rulemaking, the 30 - year averaging proposal is associated only with the implementation of CCS. This proposal does not allow 30 - year averaging for any other purpose.*********E.O. 12866 Review**

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Page **120** of **208** reduction : As used in this section, the term “available control technology” is intended to mean that the Secretary should examine the degree of emission control that has been or can be achieved through the application o f technology which is available **or** normally can be made available. This does not mean that the technology must be in actual, routine use somewhere. It does mean that the technology must be available at a cost and at a tim**e** which the Secretary determines to be reasonable. 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 their construction is seen by the committee as the most effective and, in the long run, the least expensive approach. Sen. Rep. 91 - 1196 at 16 (emphasis added). As quoted, this statement makes clear that a standard of performance may be based on a technology that is not “in actual routine use somewhere,” but that “normally can be made available.” Moreover, the technology n eed not be available until “a time which the Secretary determines to be reasonable.” Id. In addition, the D.C. Circuit has been explicit that in setting a CAA section 111 standard of performance, the EPA may make reasonable projections of what technology will be available to the regulated industry in the future. The Court state d, in Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973):*********E.O. 12866 Review**

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Page **121** of **208** We begin by rejecting the suggestion of the cement manufacturers that the Act's requirement that emission l imitations be "adequately demonstrated" necessarily implies that any cement plant now in existence be able to meet the proposed standards. Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at p resent, since it is addressed to standards for new plants -- old stationary source pollution being controlled through other regulatory authority. It is the "achievability" of the proposed standard that is in issue. * * * The * * * standard is analogous t o the one examined in International Harvester * * *. The Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on "crystal ball" inquiry **. 55**  Id. at 391 ( emphasis added). Again, although these statements in the legislative history and caselaw are in the context of establishing the basis for a standard of performance, the same principle

– - that the EPA may reasonably project the path of technological development

– - supports treating CCS as a reasonable compliance alternative. B. How did the EPA determine the other requirements for the proposed standards? 1 . Compliance Requirements The proposed compliance requirements, to the extent possible, incorporate monito ring already being performed as part of existing p art 60 and p art 75 requirements.*********E.O. 12866 Review**

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Page **122** of **208** In addition, we intend to recognize the environmental benefit of electricity generated by CHP facilities to account for the increased end use efficiency resulting from avoi ded transmission and distribution losses. Actual line losses vary from location to location, but we intend to assume a benefit of 5 percent avoided transmission and distribution losses when determining the electric output for CHP facilities. This provision would be restricted to facilities where the useful thermal output is at least 20 percent of the total output. We also propose to base compliance requirements on a 12 -month rolling average basis. The variability in GHG emissions rates is such that establ ishing a shorter averag ing period would necessitate establishing a standard to account for the conditions that result in the lowest efficiency and therefore the highest GHG emissions rate. A 12 -month rolling average accounts for variable operating conditio ns, allows consistent emissions rate averaging, allows for a more protective standard and decreased compliance burden, and simplifies compliance for state permitting authorities. Because the 12 -month rolling average can be calculated each month, this form of standard makes it possible to assess compliance and take any needed corrective action on a monthly basis. EPA proposes that it is not necessary to have a shorter averaging peri od for CO2 from these sources because*********E.O. 12866 Review**

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Page **123** of **208** the effect of GHGs on climate change depends on global atmospheric concentrations which are dependent on cumulative total emissions over time, rather than hourly or daily emissions fluctuations or local pollutant conce ntrations. Even so, we solicit comment on, in the alternative basing compliance requirements on an annual (calendar year) average basis. **V. Requirements for Modifications, Transitional Sources,**  **Reconstructions** A. Requirements for Modifications 1. Overview Under CAA section 111, existing sources are treated as new sources if they undertake “modification[s],” which are generally defined as physical or operational changes that increase emissions. CAA section 111(a)(2) and (4). The EPA’s regulations exempt certain types of changes from the definition of modification. 40 CFR 60.14(e). Available information does not indicate that there are likely to be existing affected EGUs that will undertake modifications, as that term is defined, with respect to their GHG emissions. That is because the types of projects that these EGUs are most likely to undertake that could increase GHG emissions are projects that put on pollution controls required under other CAA provisions and that emit CO 2 as a byproduct, and those type s of*********E.O. 12866 Review**

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Page **124** of **208** projects are specifically exempted from the definition of “modifications” under 40 CFR 60.14(e)(5). Because the EPA does not have information indicating that affected EGUs would undertake modifications, the EPA is not proposing any standards for modif ications. As a result, EGUs that undertake pollution control projects or other physical or operational changes would continue to be treated as existing sources and regulated through state plans. 2. Statutory and Regulatory Requirements Clean Air Act sectio n 111(b)(1)(B) requires the EPA to promulgate “standards of performance” for “new sources” within source categories. For certain pollutants, CAA section 111(d)(1) requires the EPA to prescribe regulations for state plans covering “existing source[s]” in a category regulated for that pollutant under section 111(b). Clean Air Act section 111(a)(2) defines a “new source” as “any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, propo sed regulations) prescribing a standard of performance under this section which will be applicable to such source.” Clean Air Act section 111(a)(6)defines an “existing source” as “any stationary source other than a new source.” C lean Air Act section 111(a) (4) defines “modification” as “any physical change in, or change in the method of operation of, a stationary source which increases the*********E.O. 12866 Review**

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Page **125** of **208** amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” The EPA’s regulations provide that under CAA section, for purposes of determining whether an existing electric utility steam generating unit undertakes a modification, a physical or operational change is treated as increasing emissions only when it increases the “maximum hourly emissions” above the “maximum hourly emissions achievable” at the unit. 40 CFR 60.14(h). In addition, the EPA’s regulations exempt certain physical or operational changes from the definition of modification. 40 CFR 60.14(e )(5). The exemptions include pollution control projects:

(e) The following shall not, by themselves, be considered modifications ...:

... (5) The addition or use of any system or device whose primary function is the reduction of air pollutants, except when an emission control system is removed or is replaced by a system which the Administrator determines to be less environmentally beneficial. 40 CFR 60.14(e)(5). Thus, the EPA’s current regulations define a modification as a physical or operational chan ge that increases an existing affected EGU’s maximum achievable hourly rate of emissions, but specifically exempt from that definition pollution control projects, which are projects that entail the installation of pollution control equipment or systems. 3. The EPA’s Proposed Course of Action*********E.O. 12866 Review**

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Page **126** of **208** We expect EGUs to undertake changes in the foreseeable future that will increase their maximum achievable hourly rate of CO 2 emissions, but generally, those actions will constitute pollution control projects. In many cases, those projects will involve the installation of add- on control equipment required to meet CAA requirements for conventional air pollutants . We expect that these increases in CO 2 emissions will occur as a chemical byproduct of the operation of the control equipment, and will be small. In other cases, those projects will involve equipment changes to meet the requirements of this rulemaking and that may have the effect of increasing the sources’ maximum hourly achievable emission rate, even while decreasing actual emission rate. Because all of these actions will be treated as pollution control projects under the EPA’s current NSPS regulations, they will be specif ically exempted from the definition of modification. In addition, it is conceivable that some EGUs may undertake other changes that may increase their capacity and therefore their maximum achievable hourly emission rate, but that would be so expensive so a s to fall into the category of reconstructions, under 40 CFR 60.15. Reconstructions also are not treated as modifications. Our expectation that few, if any, existing affected EGUs will undertake modifications within the meaning of the EPA’s regulations is consistent with experience under CAA section*********E.O. 12866 Review**

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Page **12 7**  of **208** 111: Historically, it has been rare that actions by sources have been treated as modifications under CAA section 111. As a result, the EPA does not think it is reasonably likely that any existing affected EGUs would undertake actions that would be defined as modifications under the CAA section 111 regulations. By the same token, the EPA is not able, at present, to determine what types of CO 2 control requirements would be appropriate for any existing affected EGUs that may undertake modifications. This is because the EPA does not have adequate information to determine what type of source may undertake modifications, what types of CO 2 controls would be appropriate, or what would be the costs of, and other relevant f actors concerning, those controls. The EPA solicits comment on all of these issues. However, at this time, the EPA is not proposing standards of performance for modifications. Accordingly, the EPA does not expect to promulgate any standards of performanc e for modifications when it takes final action on this rulemaking. The definitional provisions of CAA section 111, quoted above, make clear that a stationary source that undertakes construction or modification is considered a “new source” only if there is a proposed or final “standard of performance under this section which will be applicable to such source.” Accordingly, if there is no proposed or*********E.O. 12866 Review**

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Page **128** of **208** promulgated standard of performance applicable to a particular source, then the source cannot be considered a “new source.” Further, under the definitional provisions, any source that is not a “ new ” source is an “existing source,” and as a result of that, section 111(d) applies to that source. Therefore, affected EGUs that undertake physical or operational change s that increase their maximum achievable hourly CO 2 emission rate 56 will be treated as existing sources and therefore will not be subject to any standards of performance we finalize for new sources, but will be subject to requirements for existing sources that we intend to promulgate through a separate rulemaking and that states will be required to incorporate into state plans . This approach to these types of physical or operational changes will allow EPA to gather more information about them, which will all ow EPA to determine whether any of those changes in fact are modifications, and, if so, what control requirements would be appropriate. In the alternative, if these types of physical or operational changes were considered to be modifications, then the EPA is soliciting comment on what the appropriate standard(s) of performance for these changes should be, but, to reiterate, the EPA is not proposing any standards of performance for them at this time.

56 We discuss below the treatment of sources that reconstruct.*********E.O. 12866 Review**

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Page **129** of **208** It is important to note that at the same time that the EPA promulgated the pollution control provision in EPA’s regulations under CAA section 111, the EPA promulgated a similar provision in EPA’s NSR regulations. The D.C. Circuit , in New York v. EPA , 413 F.3d 3, 40 (D.C. Cir. 2005) , vacated the NSR pollution - control -project exemption. Because of the similarities between the NSR and the section 111 pollution control project regulatory provisions, the Court’s vacatur of the NSR regulatory provision may call into question the continued validity of the section 111 regulatory provision . As a result, we are soliciting comment on whether this exemption from the definition of “modification” for pollution control projects, under 40 CFR 60.14(e)(5), continues to be valid or not, and what course of actio n, if any, would be appropriate for the EPA to take . B. Requirements for Transitional Sources 1. Overview In today’s action, the EPA is not proposing a standard of performance for proposed affected EGUs that have received approval for their complete PSD preconstruction permits, but that have not “commenced construction” by the date of today’s proposed rulemaking. For this proposed rule, these sources are referred to as “transitional sources.” The EPA is aware of approximately 18*********E.O. 12866 Review**

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Page **130** of **208** transitional sources, seven of which are expected to utilize CCS. The EPA’s regulations define “commenced construction” as, in general, undertaking a continuous program of construction or entering into a binding contract to do so. Absent different treatment, a transitional source will be subject to the new source standards of performance when it does commence construction, even though it has already received a preconstruction permit that authorizes it to construct and operate without the controls that the EPA would now be requiring under the new source standards of performance. We are aware however that because of the specific requirements created as a result of this new standard, as a practical matter, it would be extremely difficult if not imposs ible for such a source to proceed with construction without substantial re - design of the project in order to be in compliance with the standard. There are two reasons for this. First, captured CO 2 must be sequestered or used. If this was not considered as part of the original site selection, it provides additional challenges to the sources ability to adopt CCS. Second, if CCS was not considered in the original project design, space considerations may make it difficult to accommodate in the facility’s de sign. Third, the requirement to use CCS could necessitate a change in the very generation technology that*********E.O. 12866 Review**

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Page **131** of **208** a source may choose to use. For instance, instead of building a pulverized coal boiler, IGCC technology may be more appropriate. This is not to say that CCS could not be added to a project at this stage. Projects like the AEP Mountaineer project have shown that CCS can be successfully retrofitted on an existing plant. However, unlike in an existing facility where retrofit decisions must take into a ccount previously made design decisions, in a facility in the pre - design phase, there is more opportunity for cost savings from re designing the whole project, rather than just designing it as a retrofit. The requirements created by the new source standard are very different to the point of being different in kind from post combustion controls required to meet new source standards for other pollutants which could be much more easily redesigned into a planned plant without necessitating redesign of the enti re project, since the size of the retrofit and the issues involved in disposing of the captured pollutant are generally on a smaller scale than CCS.
In light of these concerns, EPA is not proposing a standard of performance for transitional sources as lo ng as they commence construction within 12 months from the date of this proposal. Thus, these sources may construct and operate consistent with the*********E.O. 12866 Review**

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Page **132** of **208** otherwise applicable permit limits they received prior to the date of proposal of this rulemaking. 57 The EPA is not proposing a standard of performance for transitional sources that limits their emissions to the level they would emit when operating in compliance with their permits because of concerns that any such proposal would not provide environmental benefits but would create uncertainty as to the final standard of performance, and that uncertainty could prevent transitional sources from commencing construction during the 12 -month window available to them. By the same token, the EPA considered, but decided not to proceed with, soliciting comment on either a “no - control” standard of performance for transitional sources’ CO 2 emissions or a standard that equals the emission limitation that the sources identify as what they would achieve through complianc e with the otherwise applicable terms of their permit. Here too, the EPA is concerned that these approaches would not provide environmental benefits but could create uncertainty that could prevent the sources from commencing construction during the short period available to them.

57 We note that there may be some proposed natural gas - fired EGUs that are similarly situated to the coal - fired transitional sources because the natural - gas fired sources have received PSD permits but have not commenced construction by the date of this proposal. Because they are new gas - fired EGUs, we expect that they will be able to meet the requirements of the proposed new source standard of performance, so that there is no need to consider whether they merit special treatment.*********E.O. 12866 Review**

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Page **133** of **208** Because EPA is not proposing a standard of performance for transitional sources, those sources will not be treated as “new” sources, and instead will be treated as “existing” sources, as those terms are defined under CAA section 111(a). As a result, those sources would become subject to requirements for existing sources that states promulgate in accordance with EPA emissions guidelines promulgated under CAA section 111(d). 2. Background a. CAA and the EPA Regulatory Provisions . Under CAA section 111(a)(2), a “ new source ” is defined as a stationary source that has “commenced construction” or modification after the date that a standard of performance “which will be applicable to such source” is promulgated or, if earlier, proposed . Such a source becomes subject to the standard of performance that the EPA has finalized for it. The CAA does not include a definition of the term “commenced” for purposes of CAA section 111. The EPA framework regulations promulgated under CAA section 1 11 define “commenced” as follows: Commenced means, with respect to the definition of new source in section 111(a)(2) of the Act, that an owner or operator has undertaken a continuous program of construction or modification or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or modification. 40 CFR 60.2.*********E.O. 12866 Review**

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Page **134** of **208** b. Transitional Sources . The EPA is aware that in approximately 18 cases, owners or operators of proposed new coal - fired EGUs have obtained permits under the CAA PSD program for the EGUs, but have not “commenced construction”, as that term is defined under 40 CFR 60.2. Seven of these newly proposed EGUs are expected to install CCS , and the remaining o nes are not. 3. Approach Under the definition of a “new source” in CAA section 111(a)(2), if any of the approximately 18 proposed source s that have received preconstruction permits under the CAA PSD provisions have not “commenced construction” by the date of today’s proposed rulemaking , then, absent anything to the contrary in this proposal, any of those proposed sources that ultimately do commence construction would be considered “ new ” sources and subject to whatever NSPS the EPA may finalize in this rulemaking. This would be true even though the proposed source would have already incurred the expense of obtaining a PSD permit before it became subject to the NSPS. Some commenters have suggested that any of these transitional sources that do construct s hould be exempted from the new standards of performance. In contrast, newly proposed sources that did not obtain PSD permit approval before the date of this proposal would, if they construct, be treated as new sources and therefore would be subject to the new*********E.O. 12866 Review**

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Page **135** of **208** standards of performance. For these transitional sources

– - all of which are coal - fired -- the question of whether they are subject to the proposed new source standards in this rule has a significant impact because it determines whether or not they mus t be designed to accommodate CCS and, at least in the future, implement CCS . Commenters have stated that transitional sources have already incurred significant costs in obtaining a PSD permit and, in some cases, have taken other costly actions. These comme nters have stated that if transitional sources, when they commence construction, were to become treated as new sources subject to the new standards of performance, these sources may have to revise or even redesign their proposed plans and get new permits, and their expenditures to date would have to be accounted for in investment decisions going forward. Unlike conventional pollutant controls that can generally be added to a power plant without changing its basic underlying characteristics (such as type of unit or even location), CCS is more fundamental to both the design and siting of a unit, and therefore would likely involve fundamental changes to the underlying project. This is much more difficult in a project that has progressed through the permitting s tage than it would be in other types of projects. This may be true even for at least some of the seven that expect to implement CCS as they may be*********E.O. 12866 Review**

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Page **136** of **208** temporarily uncertain of their ability to comply with the requirements, proposed under this rulemaking. On the other hand, it is the EPA’s overall policy with this rulemaking that newly constructed EGUs should meet the promulgated new source performance standards. This is important to safeguard environmental values and, as discussed elsewhere, the standards are feasible for new sources. Transitional sources should have a 12 -month period, beginning from the date of proposal, to commence construction in accordance with the terms of the permit they received prior to the date of proposal of this rulemaking. The 12 -month period would not be extended for any reason, including because of any challenges to the permit that may be brought in any court or agency. Transitional sources that commence construction within that period would not be subject to the final new source limitations. This approach is generally consistent with the purposes of CAA section 111 because transitional sources would, as a matter of practice, face limits on their CO2 emissions that stem from the operational limits associated with compliance with the terms of their otherwise applicable permits. Any more stringent limits for CO 2 emissions could not be justified, for these particular sources, because such limits would require them to substantially redesign the*********E.O. 12866 Review**

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Page **137** of **208** source to meet the new limits. As previously explained, this would be true if we required the source to meet a 1,000 lb/MWh standard requiring CCS. It would also be true if we required limits even slightly tighter than those that the unit was currently designed to meet, since efficiency ( and thus CO 2 emissions) are such an integral part of unit design. The 12 -month period is appropriate because its relatively short length means that the benefits of this approach would be limited to sources that are in essence, already “shovel - ready” or ve ry close. It is those sources that would be most disadvantaged by subjecting them to the standards of performance proposed in today’s rulemaking. On the other hand, 12 months is long enough to give transitional sources a reasonable period to commence con struction in accordance with the terms of their permit. Transitional sources that do not commence construction within this period would be treated as any other affected source that commences construction after the date of proposal of this rulemaking, and would be subject to the final new source standards . Accordingly, EPA is not proposing a standard of performance in this rulemaking for transitional sources that commence construction within 12 months of this proposal. As a result, transitional sources
ma y not be treated as “new source[s]” beginning on the date of this*********E.O. 12866 Review**

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Page **138** of **208** proposal, under the definition of “new source” in CAA section 111(a)(2). Under that definition, a source may be a “new source” if it commences construction “after the publication of regulati ons (or, if early, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.” Without a standard of performance applicable to them, transitional sources that commence construction within 12 mo nths of the proposal will be treated as “existing” sources, as defined under CAA section 111(a)(6). As a result, those sources could become subject to requirements for existing sources that states impose pursuant to emissions guidelines that EPA promulgate s under CAA section 111(d)(1). Transitional sources that do not commence construction within 12 months of this proposal would be treated as any other affected source that commences construction after the date of proposal of this rulemaking, and thus would be subject to the new source standards that EPA finalizes in this rulemaking. The EPA considered, but is not pursuing, soliciting comment on subcategorizing transitional approaches as a separate category of new sources and establishing standards of perfo rmance for them that would reflect the amount of CO 2 emissions they would emit when operating in accordance with the terms of their otherwise applicable permit. For example, the EPA considered soliciting comment on a “no - control”*********E.O. 12866 Review**

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Page **139** of **208** standard of performance f or their CO 2 emissions, under which these sources would be treated as new sources subject to a standard of performance, but the standard of performance would not limit their CO 2 emissions. The EPA also considered soliciting comment on establishing a sourc e - specific standard of performance, such as one that each transitional sources itself would identify as equaling the emission limitation it would achieve through compliance with the terms of its otherwise applicable permit. The EPA is not pursuing these approaches for several reasons. First, they do not appear to offer environmental benefits because they would not lead to CO2 emissions reductions. Second, the relatively brief period of 12 months available to transitional sources to commence construction l imits the EPA’s ability to obtain sufficient information to establish the correct standard of performance. The process of establishing any standard of performance for these sources, even one that sought to finalize an emission rate fully consistent with their construction and operation under their permit, could entail some degree of uncertainty as to what precisely the final standard would be and whether the sources could meet it. That uncertainty could delay their commencing construction and thereby forc e them to miss the 12 -month window, and thereby undermine the purpose of this approach for transitional sources.*********E.O. 12866 Review**

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Page **140** of **208** C. Requirements for Reconstructions 1. Overview The EPA’s framework regulations under CAA section 111 provide that reconstructed sources

– - which, in general, are existing sources that conduct extensive replacement of components -- are to be treated as new sources and, therefore, subject to new source standards of performance. In today’s rulemaking, we take comment on options for reconstructed sources, which, in general, include (i) not taking final action to establish a new standard of performance, which, as a practical matter, would mean that reconstructed sources would be treated as existing sources; (ii) establishing the standard of performance at either the same level as for new sources or at the supercritical efficiency level ( which is the same level proposed in this rulemaking for coal - fired EGUs that employ the 30 - year alternative compliance option during the initial period after they
c onstruct and before they install CCS). 2. Background a. The EPA Regulations The EPA’s framework regulations, interpreting the definition of “new source” in CAA section 111(a)(2), 58 provide that an existing source, “upon reconstruction,” becomes subject to the standard of

58 CAA section 111 does not explicitly include provisions for reconstructed sources.*********E.O. 12866 Review**

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Page **141** of **208** performance for new sources. 40 CFR 60.15(a). The regulations define “reconstruction” as

– [T]he replacement of components of an existing facility to such 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 set forth in this part. 40 CFR 60.15(b). Thus, a reconstruction occurs if the existing source replaces components to such an extent that the capital costs of the new components exceed 50 percent of the capital costs of an entirely new facility, even if the ex isting source does not increase emissions. In addition, the component replacement constitutes a reconstruction only if it is technologically and economically feasible for the source to meet the applicable standards. The regulations go on to require the owner or operator of an existing source that proposes to replace components to an extent that exceeds the 50 percent level, to notify the EPA and to provide specified information, including “a discussion of any economic or technical limitations the facility may have in complying with the applicable standards of performance after the proposed replacements.” In addition, the regulations require the EPA to determine, within a*********E.O. 12866 Review**

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Page **142** of **208** specified time period, whether the proposed replacement constitutes a reconstruction. 40 CFR 60.15(d)

– (e). b. Reconstructions Historically, very few power plants have undertaken reconstructions. The EPA is not aware that any power plants have proposed a project that could meet the requirements for a reconstruction. 2. Options In this action, the EPA is not issuing a proposal for affected sources that undertake reconstructions. Instead, EPA solicits comment on three different options for these sources : a. Option 1: No final action to establish a standard of performance. Under the first option, at the time EPA finalizes this action, EPA would not include a standard of performance for reconstructions. This option parallels the option , descr ibed above, for modifications. Under this option, a s a practical matter, sources undertaking reconstructions would be treated as existing sources, that is, they would not be subject to any NSPS under CAA section 111(b)(2), and would instead be subject to any requirements that EPA may promulgate, and states may impose, under CAA section 111(d)(1) .*********E.O. 12866 Review**

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Page **143** of **208** This option may be justified on much the same grounds as the option for modifications, which is that the lack of information about whether sources will undertake reconstructions, and about the type of source and the type of changes, precludes proposing a NSPS. b. Option 2: E stablish a standard of performance . Under the second option, at the time EPA finalizes this action, EPA would include a standard of performance for reconstructions at , as one sub - option, the same level as for new sources or, as another sub - option, at the supercritical efficiency level . Under this option, sources undertaking reconstructions would be treated as new sources. This option may be justified on grounds that a source undertaking a reconstruction is rebuilding its plant to such an extent that it should be obligated to implement a higher level of emissions control. This option may find further support because under the definition of “reconstruction” quoted above, a source’s rebuilding project becomes treated as a rec onstruction only if it is “technologically and economically feasible [for the source] to meet the applicable standards.” 40 CFR 60.15(a). EPA requests comment on whether applying significantly less stringent emission limits to a reconstructed EGU than to an entirely new EGU would create perverse incentives for a company to make large investments (over 50 percent of the cost of a new source) in an*********E.O. 12866 Review**

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Page **144** of **208** existing EGU to extend its economic life for decades rather than build an entirely new, lower - emitting EGU. EPA also requests comment on whether the alternative CCS compliance option for new sources -- which would allow the new source standard to be met on a 30 - year average basis -- should be available to reconstructed sources under this option. It should be noted that because EPA is not proposing a NSPS for reconstructions, even if EPA takes final action establishing a NSPS for reconstructions, any source that commences construction, between the date of this proposal and the date of final action for this rulemaking , on a project, would not be treated as having undertaken a reconstruction even if the project would have been considered a reconstruction had the source commenced construction after the final action. The EPA solicits comment on all aspects of these option s for reconstructions. **V I.**  **Implications for PSD and Title V programs**  A. Overview The proposal in this rulemaking would, for the first time, regulate GHGs under CAA section 111. Under the EPA’s regulations for the CAA PSD preconstruction permit program, and the CAA Title V operating permit program, regulation of GHGs under CAA section 1 11*********E.O. 12866 Review**

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Page **145** of **208** triggers the applicability of PSD. Even so, today’s proposal should not require any additional SIP revisions to make clear that the Tailoring Rule thresholds continue to apply to the PSD program . This issue arises because, although PSD has already been triggered for sources and although the Tailoring Rule thresholds already apply, the EPA’s regulatory provisions could be read to suggest that the EPA’s promulgation of CAA section 111 requirements for a pollutant previously unregulated under CAA section 1 11 could, in effect, trigger PSD requirements again. However, the EPA included an interpretation in the Tailoring Rule preamble, which makes clear that the Tailoring Rule thresholds continue to apply if and when the EPA promulgates requirements under CAA s ection 111. Even so, in today’s proposal, the EPA is including a provision in the CAA section 111 regulations that confirms this interpretation. However, if a state with an approved PSD SIP program that applies to GHGs believes that if the EPA were to fin alize the rulemaking proposed today, the state would be required to revise its SIP to make clear that the Tailoring Rule thresholds continue to apply, then (i) the EPA encourages the state to do so as soon as possible, and (ii) the EPA will proceed with a separate rulemaking action to narrow its approval of that state’s SIP so as to assure that for federal purposes, the Tailoring Rule thresholds will*********E.O. 12866 Review**

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Page **146** of **208** continue to apply as of the effective date of today’s rulemaking. In the alternative, if it is not the case that the Tailoring Rule thresholds continue to apply if and when the EPA promulgates requirements under CAA section 111, then EPA will shortly proceed with a separate rulemaking action to narrow its approval of all of the State’s approved SIP PSD programs so assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of today’s proposal. As discussed below, i n the case of title V, today’s rulemaking does not have implications for the Tailoring Rule thresho lds established with respect to sources subject to title V requirements. B. Implications for PSD Program 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 required to obtain a preconstruction permit. This permit assures that the source meets specified requirements, including application of best available cont rol technology. States are required to include an approved PSD program in their SIPs and to issue the PSD permits, but if a state does not have such a program, then the EPA issues the PSD permits.*********E.O. 12866 Review**

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Page **147** of **208** Regulation of GHG emissions in the Light Duty Vehicle Rul e, triggered applicability of regulatory requirements to stationary sources under the PSD and title V provisions of the CAA. Hence, o n June 3, 2010 (75 FR 31514), the EPA issued the “Tailoring Rule,” which establishes thresholds for GHG emissions in order to define and limit when new and existing industrial facilities must have permits under the PSD and title V programs . The rule addresses emissions of six GHGs: CO 2 , CH 4 , N 2 O, HFCs, PFCs and SF 6 . On January 2, 2011, large industrial sources, including power plants, became subject to permitting requirements for their GHG emissions if they otherwise are required to obtain a PSD or title V permit due to emissions of other air pollutants. We recognize that because of the way that the EPA’s PSD regulations are written, promulgating the rule we propose today may raise questions as to whether the EPA must revise its PSD regulations

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

– - to assure that the Tailoring Rule thresholds will continue to app ly to sources subject to PSD. That is, under the EPA’s regulations, PSD applies to a “major stationary source” that undertakes construction, 40 CFR 51.166(a)(7)(i), and to a “major modification.” 40 C FR 51.166(a)(7)(iii). A “major modification” is defined as “any physical change in or change in the method of operation of a major stationary*********E.O. 12866 Review**

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Page **148** of **208** source that would result in a significant emissions increase . . . and a significant net emissions increase . . . .” Thus, for present purposes, the key component of these applicability provisions is that PSD applies to a “major stationary source.” This term is the regulatory replacement for the term “major emitting facility,” which is central to the PSD applicability requirements established in the CAA itself, under sections 165(a)(1) and 169(1). The EPA’s regulations define the term “major stationary source” as a “stationary source[] of air pollutants which emits, or has the potential to emit, 100 [or, depending on the source category, 250] tons per year or more of any regulated NSR pollutant.” 40 CFR 51.166(b)(1)(i)( a ). The EPA’s regulations go on to define “regulated NSR pollutant” as follows, in relevant part:

(b)(49) Regulated NSR pollutant, for purposes of this section, means the following: (i) Any pollutant for which a national ambient air quality standard has been promulgated and any pollutant identified under this paragraph (b)(49)(i) as a constituent or precursor to such pollutant... . (ii) Any pollutant that i s subject to any standard promulgated under section 111 of the Act; (iii) Any Class I or II substance subject to a standard promulgated under or established by title VI of the Act;*********E.O. 12866 Review**

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Page **149** of **208** (iv) Any pollutant that otherwise is subject to regulation under the Act as defined in paragraph (b)(48) of this section.... 40 CFR 51.166(b)(49). Thus, the PSD regulations contain a separate PSD trigger for pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the “NSPS trigger provision”), so that as soon as the EPA promulgates the first NSPS for a particular air pollutant, as we are doing in this rulemaking with respect to the GHG air pollutant, then PSD is triggered for that air pollutant. The Tailoring Rule, on the face of its regulatory provisions, incorporated the revised thresholds it promulgated into only the fourth prong (“[a]ny pollutant that otherwise is subject to regulation under the Act”), and not the second prong (“[a]ny pollutant that is subject to any standard promulgated under section 111 of the Act”). For this reason, a question may arise as to whether the Tailoring Rule thresholds apply to the PSD requirement as triggered by the NSPS that the EPA is promulgating in this rulemaking. If, under the language of the PSD regulations, the Tailoring Rule thresholds do **not** apply to the NSPS trigger provision, then the EPA would have to revise its regulations to include the Tailoring Rule thresholds. Moreover, under these circumstances, the s tates that*********E.O. 12866 Review**

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Page **150** of **208** apply PSD to GHG - emitting sources may have to revise their SIPs, and do so quite promptly. However, although the Tailoring Rule thresholds on their fac e apply to only the term, “subject to regulation” in the definition of “regulated NSR pollutant,” the EPA stated in the Tailoring Rule preamble that the thresholds should be interpreted to apply to other terms in the definition of “major stationary source” and in the statutory provision, “major emitting facility.” Specifically, the EPA stated: 3 . Other Mechanisms As just described, we selected the “subject to regula tion” mechanism because it most readily accommodated the needs of States to expeditiously revise

– through interpretation or otherwise -- their state rules . Even so, it is important to recognize that this mechanism has the same substantive effect as the me chanism we considered in the proposed rule, which was revising numerical thresholds in the definitions of major stationary source and major modification . Most importantly, although we are codifying the “subject to regulation” mechanism, that approach is dr iven by the needs of the states, and our action in this rulemaking should be interpreted to rely on any of several legal mechanisms to accomplish this result . Thus, our action in this rule should be understood as revising the meaning of several terms in these definitions, including: (1) the numerical thresholds, as we proposed; (2) the term, “any source,” which some commenters identified as the most relevant term for purposes of our proposal; (3) the term, “any air pollutant; or (4) the term, “subject to regulation.” The specific choice of which of these constitutes the nominal mechanism does not have a substantive legal effect because each mechanism involves one or another of the components of the terms “major stationary source” - which embodies the statu tory term,*********E.O. 12866 Review**

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Page **151** of **208** “major emitting facility” -- and “major modification,” which embodies the statutory term, “modification,” and it is those statutory and regulatory terms that we are defining to exclude the indicated GHG - emitting sources. [Footnote] [Footnote : We also think that this approach better clarifies our long standing practice of interpreting open ended SIP regulations to automatically adjust for changes in the regulatory status of an air pollutant, because it appropriately assures that the Tailoring Rule applies to both the definition of “major stationary source” and “regulated NSR pollutant.” ] 75 FR 31582. Thus, according to the preamble, the definition of “major stationary source” itself already incorporates the Tailoring Rule thresholds, and n ot just through one component (the “subject to regulation” prong of the term “regulated NSR pollutant”) of that definition. For this reason, it is the EPA’s position that the Tailoring Rule thresholds continue to apply even when the EPA promulgates the fir st NSPS for GHGs (which, as noted above, triggers the PSD requirement under the NSPS trigger provision in the definition of “regulated NSR pollutant”) . To clarify and confirm that the Tailoring Rule thresholds apply to the section 111 prong of the definiti on of regulated NSR pollutant, in this proposed rulemaking, the EPA is proposing to revise the NSPS regulations, although not the PSD regulations, to explicitly make clear that the NSPS trigger*********E.O. 12866 Review**

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Page **152** of **208** provision in the PSD regulations incorporate the Tailoring Rul e thresholds . As a result, the EPA believes that s tates that incorporated the Tailoring Rule thresholds into their SIPs may take the position that they also incorporated EPA’s interpretation in the preamble that the thresholds apply to the definition “majo r stationary source.” The EPA requests that all s tates with approved SIP PSD programs that apply to GHGs indicate during the comment period on this rule whether they can interpret their SIPs already to apply the Tailoring Rule thresholds to the NSPS prong or whether they must revise their SIPs. For any s tate that says it must revise its SIP (or that does not respond), the EPA expects to propose a rule that is comparable to the SIP PSD Narrowing Rule shortly after the close of the comment period, and expec ts to finalize that rule at the same time that it finalizes this NSPS rule. C. Implications for Title V Program Under the title V program, a source that emits any air pollutant subject to regulation at or above specified thresholds (along with certain other sources) is required to obtain an operating permit. This permit includes all of the CAA requirements applicabl e to the
source. These permits are generally issued through EPA- approved State title V programs .*********E.O. 12866 Review**

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Page **153** of **208** As the EPA explained in the Tailoring Rule preamble, title V applies to a “major source,” CAA section 502(a), which is defined to include, among other things, certain sources, including any “major stationary source,” CAA section 501(2)(B), which, in turn, is defined to include a stationary source of “any air pollutant” at or above 100 tpy. CAA section 302(j). The EPA’s regulations under title V define the term “major source,” and in the Tailoring Rule, the EPA revised that definition to make clear that the term is limited to stationary sources that emit any air pollutant “subject to regulation.” The EPA incorporated the Tailoring Rule threshold within this defini tion of “subject to regulation.” The EPA described its action as follows in the preamble to the Tailoring Rule:

Thus, EPA is adding the phrase “subject to regulation” to the definition of “major source” under 40 CFR 70.2 and 71.2 . EPA is also adding to these regulations a definition of “subject to regulation.” Under the part 70 and part 71 regulatory changes adopted, the term “subject to regulation,” for purposes of the definition of “major source,” has two components . The first component codifies the general approach EPA recently articulated in the “ Reconsideration of Interpretation of Regulations That Determine Pollutants Covered by Clean Air Act Permitting .” 75 FR 17704 . Under this first component, a pollutant “subject to regulation” is defined to me an a pollutant subject to either a provision in the CAA or regulation adopted by EPA under the CAA that requires actual control of emissions of that pollutant and that has taken effect under the CAA . See id . at 17022 - 23; Wegman Memo randum at 4 - 5 . To addres s tailoring for GHGs, EPA includes a second component of the definition of “subject to regulation,” specifying that GHGs are not subject to regulation for purposes of defining a major source, unless as of July 1,*********E.O. 12866 Review**

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Page **154** of **208** 2011, the emissions of GHGs are from a sour ce emitting or having the potential to emit 100,000 tpy of GHGs on a CO 2 e basis. 75 Fed. Reg. at 31,583. Unlike the PSD regulations described above, the title V definition of “major source” , as revised by the Tailoring Rule, do es not on its face distinguish among types of regulatory triggers for title V. Because title V has already been triggered for GHG - emitting sources, the promulgation of CAA section 111 requirements has no further impact on title V requirements for major sources of GHGs . Accordingly, today’s rulemaking has no title V implications with respect to the Tailoring Rule threshold. Of course, unless exempted by the Administrator through regulation under CAA section 502(a), sources subject to a NSPS are 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 requirements. We have concluded that this rule will not affect non major sources and there is no need to consider whether to exempt non major sources **VII. Impacts of the Proposed Action** G. What are the air impacts? H. What are the energy impacts? I. What are the compliance costs? J. How will this proposal contribute to climate change protection? K. What are the economic and employment impacts?*********E.O. 12866 Review**

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Page **155** of **208** EPA does not anticipate that th is proposed rule will result in notable CO 2 emission changes, energy impacts, monetized benefits, costs, or economic impacts by 2020. Essentially the EPA believes that owners of newly built electric generating units will choose technologies that meet these standards due to existing economic conditions as normal business practice . Likewise, we believe this rule will not have any impacts on the price of electricity, employment or labor markets, or the US economy. L. What are the benefits of the proposed standards? As previously stated, EPA does not anticipate that the power industry will incur compliance costs as a result of this proposal and we do not anticipate any notable CO 2 emission changes resulting from the ru le. Therefore, there are no direct monetized climate benefits in terms of CO 2 emission reductions associated with this rulemaking. **VI II. Request for Comments**  We request comments on all aspects of the proposed rulemaking . All significant comments received will be considered in the development and selection of the final rule . We specifically solicit comments on additional issues under consideration as described below. CEMS. We are considering and requesting comment on requiring the use of CO 2 CEMS including stack gas flow rate monitoring for all new affected facilities, including those burning exclusively natural gas*********E.O. 12866 Review**

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Page **156** of **208** and/or distillate oil. In addition, we are requesting comment on requiring the use the following measurement procedures in conducting CEMS relative accuracy testing: a. EPA Method 2F of 40 CFR part 60 for flow rate measurement during the relative accuracy test audit and performance testing. Method 2F provides velocity data for three dimensions and provides measurements more representative of actual gas flow rates than EPA Method 2 or 2G of 40 CFR part 60. b. EPA Method 2H of 40 CFR part 60 or Conditional Test Method (CTM) - 041 (see: http://www.epa.gov/airmarkets/emissions/docs/square
- ducts wall - effects - test -me thod- ctm- 041.pdf ) to account for wall effects on for stack gas flow rate calculations during CEMS relative accuracy determinations and for performance testing. c. EPA Method 4 of 40 CFR part 60 to determine moisture for flow rate during CEMS relative accur acy determinations and for performance test calculations. d. EPA Method 3A of 40 CFR part 60 for CO 2 concentration measurement and for molecular weight determination during CEMS relative accuracy determinations or for performance testing. Account for ambie nt air argon concentration of 0.93 percent 59 and a molecular weight of 39.9 lb/lb
-mol in calculating the dry gas molecular weight.

59 http://www.physicalgeography.net/fundamentals/7a.html*********E.O. 12866 Review**

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Page **157** of **208** e. Measure the stack diameter at the CEMS measurement site and the reference method sampling site with a laser distance measur ement device. Determine the mean average of three separate diameter measurements for circular stack areas or the mean average of three depth and width measurements for rectangular measurement areas. Calculate the effective stack area for all flow rate meas urements, both CEMS system and Reference Method, using this measurement data. This would be a one - time measurement that would fix the effective area of the stack emissions point unless a new location is chosen for the CEMS or Reference Method measurement p oint. All calculations involving pi would us e a value of 3.14159. f. Apply a daily calibration drift criteria not to exceed 0.3 percent CO 2 for CO 2 CEMS. g. Do not exceed a relative accuracy specification of 2.5 percent for both CO 2 and flow rate measureme nt CEMS. We also request comment on whether Method 3B of 40 CFR part 60 (integrated bag sample), in addition to Method 3A, should be allowed for CO 2 concentration measurement and for molecular weight determination during CEMS relative accuracy determinatio ns or for performance testing. Coal refuse . Due to the multiple environmental benefits of remediating coal refuse piles, we are considering and requesting*********E.O. 12866 Review**

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Page **158** of **208** comment on subcategorizing EGUs that burn over 75 percent coal refuse on an annual basis. As part of the GHG listening sessions, one commenter mentioned the advantages of utilizing coal refuse to create electricity . The commenter stated that if net emissions caused by using mining waste to generate electricity are calculated , then mining waste facility would produce no net GHG emission s in the long term and emission s would be no greater than the short term emissions of a combined cycle gas plant in. The comment states that due to the size of the piles , mining waste pile e xposure to atmospheric oxygen and pressure promotes heat - generating reactions, primarily oxidation of the mining waste itself (i.e., the coal refuse piles are slowly burning) . This process emits CO 2 and other air pollutants . Remediati o n would stop current and future CO 2 emissions resulting from the uncontrolled combustion of waste piles . Coordinates. We realize that geographic latitude and longitude coordinates of each stack in terms of decimal degrees are presently reported to the EPA’s Clean Air Markets Division in terms of four decimal points to the right of the decimal point. We are requesting comment on whether we should require owners/operators of affected facilities to submit to the EPA Administrator the geographic latitude and longitude coordinates of each stack to have at least six values to the right of the decimal for each location. By way of example, the*********E.O. 12866 Review**

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Page **159** of **208** coordinates for the monument next to Zachary Taylor’s tomb in Louisville, KY are 38.279401 latitude and - 85.643751 longitude. Format of the Proposed Standards . Although we have proposed gross output -based emission standards, the EPA believes that the net power supplied to the end user is a better indicator of environmental performance than gross output from the power producer. Net output is the combination of the gross el ectrical output of the electric generating unit minus the parasitic power requirements. A parasitic load for an electric generating unit is any of the loads or devices powered by electricity, steam, hot water, or directly by the gross output of the electri c generating unit that does not contribute electrical, mechanical, or thermal output. In general, less than 7. 5 percent of coal - fired station power output, and about 2.5 percent of
a combined cycle station power output, is used internally by parasitic energy demands , but the amount of these parasitic loads vary from source to source. Reasons for using net output include 1) recognizing the efficiency gains of selecting EGU designs and control equipment that require less auxiliary power, 2) selecting fuel s that require less emissions control equipment, and 3) recogniz ing the environmental benefit of higher efficiency motors, pumps, and fans. In addition, use of a gross output -based standard could potentially drive the installation of electrically driven fe ed pumps instead of*********E.O. 12866 Review**

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Page **160** of **208** steam driven feed pumps , even though f rom an overall net efficiency basis , it may be more efficient to use steam- driven feed pumps . Further, monitoring net output for new and reconstructed facilities can be designed into the facility at low costs. Thus, we are requesting comment on the use of net output -based emission standards for owners/operators of new facilities. Potential Electric Output . The proposed rule uses three criteria to determine applicability : heat input of fossil fuel mus t be greater than 250 MMBtu/h, 25 MW or more net electricity must be sold to the grid, and one - third of potential electric output must be sold to the grid. In addition, we are propos ing to exempt stationary combustion turbines that are subject to a federal ly enforceable permit to limit operate less than 3,000 hours annually. We are proposing to base the potential electric output for stationary combustion turbines on an assumed efficiency of fifty percent instead of the thirty- three percent used for boiler/s team turbine -based facilities. We have concluded that this is appropriate because the potential electric output factor, and not the capacity factor requirement exempting combustion turbines operating less than 3,000 hours annually, could otherwise be the c ontrolling factor on whether combustion turbines used for peaking operations are considered affected facilities. If we used 33 percent instead of 50 percent , it could inadvertently*********E.O. 12866 Review**

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Page **161** of **208** encourage the installation of less efficient peaking combustion turbines. For example, if an owner/operator has the option to either purchase a 30 or 35 percent efficient combustion turbine , the less efficient turbine could be permitted to operate more hours . Since potential electric output is based on the heat input, the potential electric output using a 33 percent efficiency factor would limit operation of the more efficient turbine to 2,800 hours annually. In contrast, the less efficient turbine would be p ermitted to operate 3,200 hours annually before applicability based on potential electric output applied. Using the 50 percent efficiency assumption eliminates this issue and bases applicability on permitted capacity factor, while still accommodating for the intended exemption to combined heat and power facilities. We are requesting comment on whether the potential electric output should be changed or eliminated for this rule. As currently proposed, an owner/operator of an electric only boiler/steam turbi ne based generator could take a permit restriction that would essentiall y limit operation to less than 2 , 920 hours annually to avoid applicability with the proposed requirements. Since between 5 to 10 percent of boiler/steam turbines presently operate less than 3 ,000 hours annually , this could encourage owners/operators to take operating permit restrictions on their facilities primarily used for*********E.O. 12866 Review**

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Page **162** of **208** peaking operations to avoid applicability with the GHG requirements . Consequently, they would not be required to redu ce their corresponding emission rates. While this approach reduces the environmental benefit of the proposed rule, it would lower compliance costs because facilities could be maintained for peaking applications and grid reliability issues without the c apital improvements that would otherwise be required. Another alternative would be to specify that the potential electric output capacity exemption only applies to CHP facilities. We are also considering and requesting comment on if exempting all CHP facil ities where useful thermal output accounts for at least 20 percent of the total useful output from this proposed rule would recognize the environmental benefit of CHP and result in additional installations that would otherwise no occur. In considering exemption of CHP units, EPA is particularly interested in the overall impact this would have on the composition of new builds. The definition of affected sources under this rule already exempts CHP sources that primarily generate on - site power. Therefore, a s explained earlier, today’s proposal does not impact any of the small amount of projected coal - fired CHP in EIA’s AEO 2011. CHPs that would be covered by this rule generate and sell large quantities of electricity. While building such units is more energy efficient and results in some GHG reductions, building new coal - fired units to meet*********E.O. 12866 Review**

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Page **163** of **208** a standard of 1,000 lb/MWh would likely result in greater reductions. If potential developers of new coal - fired generation opted instead to build coal - fired CHP to avoi d the CO 2 limitations proposed under today’s rule, it could result in greater emissions of CO 2 . Furthermore, requiring such units to meet a standard of 1,000 lb/MWh does not preclude new coal - fired units from being CHP units. Simple Cycle Turbines . As stat ed in the preamble, the intent of the proposed regulations is to cover stationary combustion turbines use for intermediate and base load electric power generation and to exempt stationary combustion turbines used for peaking operations (i.e., simple cycle turbines). Instead of defining a simple cycle turbine in the regulatory text, we base applicability of the stationary combustion turbine on if it is permitted to operate 3,000 hours or more annually. The peaking season is generally considered to be less than 2,500 hours annually, and we have concluded the proposed capacity factor provides sufficient margin for operational flexibility. We have concluded that a permitted capacity is more appropriate than defining a simple cycle turbine. We are specifically
re questing comment on if we should (1) change the capacity threshold or (2) add a definition and base the applicability on the definition. For the final rule we are considering a capacity range of 2,500 to 3,500 hours annually. In the event we use the defini tion approach, we*********E.O. 12866 Review**

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Page **164** of **208** are requesting comment on whether a CHP facility that uses the recovered exhaust heat for purposes other than to generate steam and recuperated combustion turbines should be considered simple or combined cycle combustion turbines. **IX . Sta** **tutory and Executive Order Reviews** A. Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review Under EO 12866 (58 FR 51,735, October 4, 1993), this action is a “significant regulatory action” because it “raises novel legal or policy issues arising out of legal mandates”. Accordingly, EPA submitted this action to the Office of Management and Budget ( OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action. In addition, EPA prepared an analysis of the potential costs and benefit s associated with this action. This analysis is contained in the Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units . The EPA believes this rule will have no compliance costs associated with it, because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this*********E.O. 12866 Review**

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Page **165** of **208** proposal because of existing and expected market conditions. B. Paperwork Reduction Act As required by the P aperwork Reduction Act (PRA) , 44 U.S.C. 3501 et seq. **,** an information collection request (ICR) will be prepared by EPA (ICR No. XXXX.XX) and submitted for approval to the Office of Management and Budget (OMB) **.** The information collection requirements are based on notification, recordkeeping, and reporting requirements in the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies se t forth in 40 CFR part 2, subpart B. The information collection requirements are not enforceable until OMB approves them. Apart from the recordkeeping and reporting costs, we do not expect other compliance costs for most units, as the information require d by this proposed rule is already collected and reported by other regulatory programs. The EPA is accepting comment on the need for this information, the accuracy of the provided burden estimates, and any suggested*********E.O. 12866 Review**

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Page **166** of **208** methods for minimizing respondent burden, including the use of automated collection techniques. The EPA has established a public docket for this proposed rule, which includes this ICR, under Docket ID number EPA- HQ - OAR- 201 1 - 0660 . The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal. C. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. et seq. The Regulatory F lexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, sma ll entity is defined as: (1) A small business that is defined by the SBA ’s regulations at 13 CFR 121.201 (f or the electric power generation industry, the small business size standard is an ultimate parent entity defined as having a total electric output o f 4 million MWh or less in the previous*********E.O. 12866 Review**

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Page **167** of **208** fiscal year. The NAICS codes for the affected industry are in Table 4 below ); (2) A small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) A small organization that is any not - for -profit enterprise which is independently owned and operated and is not dominant in its field. **T able**  **4 . P** **otentially R** **egulated C** **ategories and**  **E ntities**  **a Category**  **NAICS**

**Code Examples of Potentially Regulated**  **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 Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and stationary combined cycle combustion turbines) . b Federal, state , or local government - owned and operated establishments are classified according to the activity in which they are engaged.*********E.O. 12866 Review**

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Page **168** of **208** After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a sub stantial number of small entities. See, e.g. , ; Michigan v. EPA, 213 F.3d 663 , 689 (D.C. Cir. 2000) ("The court has consistently held that the RFA imposes 'no obligation to conduct a small entity impact analysis of effects on entities which it does not regu late.'" (citing Motor & Equip. Mfrs. Ass'n. v. Nichols, 142 F.3d 449, 467 (D.C.Cir.1998) (quoting United Distribution Cos. v. FERC, 88 F.3d 1105, 1170 (D.C.Cir.1996))) ; Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855 (D.C. Cir. 2001) ; Am. Trucking Ass ’n v. EPA, 175 F.3d 1027 (D.C. Cir. 1999); Mid- Tex Elec. Co - op, Inc. v. FERC, 773 F.2d 327 (D.C. Cir. 1985). We do not include an analysis of the illustrative impacts on small entities that may result from implementation of this proposed rule by state s because we do not anticipate any compliance costs as a result of this proposal. Thus the cost - to - sales ratios for any affected small entity would be zero costs as compared to annual sales revenue for the entity. The EPA does not project any new coal - fired EGUs to be built , so , accordingly, there are no anticipated economic impacts as a result of this proposal . Nevertheless, the EPA is aware that there is substantial interest among small entities (municipal and rural electric*********E.O. 12866 Review**

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Page **169** of **208** cooperatives) that will be a ffected by this rule. In light of this interest, the EPA determined to seek early input from representatives of small entities while formulating the provisions of this proposed regulation. Such outreach is also consistent with the President’s January 18, 2 011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, which emphasizes the important role small businesses play in the American economy. This process has enabled the EPA to hear directly from these representatives, at a very prelimina ry stage, about how it should approach the complex question of how to apply Section 111 of the CAA to the regulation of GHGs from these source categories. The EPA conducted an initial outreach meeting with small entity representatives on April 6, 2011. The purpose of the meeting was to provide an overview of recent EPA proposals impacting the power sector. Specifically, overviews of the Transport Rule, the Mercury and Air Toxics Standards, and the Clean Water Act 316(b) Rule proposals were presented. The EPA conducted outreach with representatives from 20 various small entities that potentially would be affected by this rule. The representatives included small entity municipalities, cooperatives, and private investors. We distributed outreach materials to the small entity representatives; these materials included background, an*********E.O. 12866 Review**

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Page **170** of **208** overview of affected sources and GHG emissions from the power sector, an overview of CAA section 111, an assessment of CO 2 emissions control technologies, potential impacts on small en tities, and a summary of the listening sessions. We met with eight of the small entity representatives, as well as three participants from organizations representing power producers, on June 17, 2011, to discuss the outreach materials, potential requiremen ts of the rule, and regulatory areas where the EPA has discretion and could potentially provide flexibility. A second outreach meeting was conducted on July 13, 2011. We met with nine of the small entity representatives, as well as three participants from organizations representing power producers . During the second outreach meeting, various small entity representatives and participants from organizations representing power producers presented information regarding issues of concern with respect to development of standards for GHG emissions. Specifically, topics discussed included: boilers with limited opportunities for efficiency improvements due to NSR complications for conventional pollutants; variances per kilowatt - hour and in heat rates over monthly and annual operations; significance of plant age; legal issues; importance of future determination of carbon neutrality of biomass; and differences between municipal government electric utilities and other utilities.*********E.O. 12866 Review**

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Page **171** of **208** Written comments that the EPA received from, or on behalf of, small entities in response to discussions at the outreach meetings and questions posed to the small entity representatives have been placed in the docket for this rulemaking. We invite comments on all aspects of the proposal and its impacts, including potential adverse impacts, on small entities. D. Unfunded Mandates Reform Act of 1995 This action contains no Federal mandates under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531 - 1538 for State, local, or tribal governments or the private sector . The action imposes no enforceable duty on any State, local or tribal governments or the private sector. Therefore, this action is not subject to the requirements of sections 202 or 205 of the UMRA. This action is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. Consistent with the intergovernmental consultation p rovisions of UMRA section 204, the EPA has initiated consultations with governmental entities affected by this proposed rule. The EPA invited the following 10 national organizations representing state and local elected officials to a meeting held on April 12, 2011, in Washington*********E.O. 12866 Review**

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Page **172** of **208** DC: 1) National Governors Association; 2) National Conference of State Legislatures, 3) Council of State Governments, 4) National League of Cities, 5) U.S. Conference of Mayors, 6) National Association of Counties, 7) International City/County Management Association, 8) National Association of Towns and Townships, 9) County Executives of America, and 10) Environmental Council of State s. These 10 organizations of elected state and local officials have been identified by the EPA as the “Big 10” organizations appropriate to contact for purpose of consultation with elected officials. The purposes of the consultation were to provide general background on the proposal, answer questions, and solicit input from state /local governments. During the meeting, officials asked clarifying questions regarding CAA section 111 requirements and efficiency improvements that would reduce CO 2 emissions. In addition, they expressed concern with regard to the potential burden associated with impacts on state and local entities that own/operate affected utility boilers, as well as on state and local entities with regard to implementing the rule. Officials requested, and the EPA provided, addresses associated with the 123 state and local governments estimated to be potentially impacted by the proposed rule. Subsequent to the April 12, 2011 meeting, the EPA received a letter from the National Conference of State Legislatures. In that letter, the*********E.O. 12866 Review**

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Page **173** of **208** National Conference of State Legislatures urged the EPA to ensure tha t the choice of regulatory options maximizes benefit and minimizes implementation and compliance costs on state and local governments; to pay particular attention to options that would provide state s with as much flexibility as possible; and to take into c onsideration the constraints of the state legislative calendars and ensure that sufficient time is allowed for state actions necessary to come into compliance. The EPA offered consultation to 584 tribal officials early in the process of developing this proposed regulation. C onsultation/outreach was conducted with several tribes. The Consultation and Coordination with Indian Tribal Governments discussion in this preamble includes a description of the consultation /outreach . The EPA also conducted outreach to small entities that potentially would be subject to the requirements of the rule to obtain their advice and recommendations. The RFA discussion in this preamble describes the outreach. E. Executive Order 13132, Federalism This 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*********E.O. 12866 Review**

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Page **174** of **208** distribution of power and responsibilitie s among the various levels of government, as specified in Executive Order 13132 . This action does not impose direct compliance costs on state or local governments. Thus, Executive Order 13132 does not apply to this action . The EPA consulted with state and local officials in the process of developing the proposed rule to permit them to have meaningful and timely input into its development. The EPA met with 10 national organizations representing state and local elected officials to provide general background on the proposal, answer questions, and solicit input from state/local governments. The UMRA discussion in this preamble includes a description of the consultation. In the spirit of EO 13132, and consistent with EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this proposed action from state and local officials. F. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by tribal*********E.O. 12866 Review**

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Page **175** of **208** governments, or EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement. EPA has concluded that this action may have tribal implications. However, it will neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. This proposed rule would impose requirements on owners and operators of EGUs. The EPA is aware of three coal - fired EGUs located in Indian Country but is not aware of any EGUs owned or operated by tribal entities. The EPA notes that this proposal does not affect existing sources such as the three coal - fired EGUs located in Indian Country, but addresse s CO 2 emissions for new EGU sources only. In addition, the EPA is aware of other Tribal interests that could be impacted by this rule. As a result, the EPA offered consultation with t r ibal officials early in the process o f developing this proposed regulati on to permit them to have meaningful and timely input into its development. Consultation letters were sent to 584 tribal leaders. The letters provided information regarding 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*********E.O. 12866 Review**

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Page **176** of **208** of Ojibwe. Other tribes participated in the call for information ga thering purposes. In this meeting, the EPA provided background information on the GHG emission standards to be developed and a summary of issues being explored by the Agency. Tribes suggested that the EPA consider expanding coverage of the GHG standards to include combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture more EGUs, and including credit for use of renewables. The tribes were also interested in the scope of the emissions averaging being considered by the Agenc y (e.g., over what time period, across what units). In addition, the EPA held a series of listening sessions on this proposed action. A few tribes were invited to participate in a session on February 17, 2011 with the state agencies, and a separate session was held with the tribes on April 20, 2011. The EPA will also hold additional meetings with tribal environmental staff to inform them of the content of this proposal as well as provide additional consultation with tribal elected officials where it is appropriate. We specifically solicit additional c omment on this proposed rule from tribal officials. G. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks This action is not subject to EO 13045 (62 FR 19885, April 23,*********E.O. 12866 Review**

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Page **177** of **208** 1997) because it is not economically signif icant as defined in EO 12866. This proposed rule is not subject to EO 13045 because the proposal likely does not produce changes in emissions of greenhouse gases or other pollutants (but it does encourage the current trend towards cleaner generation, helpi ng to protect air quality and children's health). The Agency recognizes that children are among the groups most vulnerable to climate change impacts and the public is invited to submit comments or identify peer reviewed studies relevant to this proposal. M. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. This action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry. N. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low- Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent*********E.O. 12866 Review**

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Page **178** of **208** practicable and permitted by law, to make environmental justice part of their mission by identifying 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. EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority or low- income population s, because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low- income population. These proposed standards will improve public health and welfare in the future by providing legal assurance that primary CO 2 emissions from newly constructed electric generating units potentially contributing to climate change and ocean acidification are limited to the levels proposed in this rulemaking. Reduced CO 2 emissions from the power sector would benefit all populations. However, within communities experiencing climate change, certain parts of the population may be especially vulnerable to its adverse effects; these include the poor, the elderly, those already in poor health, the disabled, those living alone, and indigenous populations dependent on*********E.O. 12866 Review**

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Page **179** of **208** one or a few resources. In addition, the U.S. Climate Change Science Program stated as one of its conclus ions: ”The United States is certainly capable of adapting to the collective impacts of climate change. However, there will still be certain individuals and locations where the adaptive capacity is less and these individuals and their communities will be di sproportionately impacted by climate change.” These specific sub -populations may receive particularly important benefits from reductions in GHGs. O. National Technology Transfer and Advancement Act Section 12(d) of the NTTAA of 1995 (Public Law No. 104 - 113 ; 15 U.S.C. 272 note) directs the EPA to use Voluntary C ensus S tandards in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs the EPA to provide Congress, through annual reports to the OMB, with explanations whe n an agency does not use available and applicable VCS . This rulemaking involves technical standards. The EPA cites the following standards in this proposed rule: EPA Methods 1 ( Sample and velocity traverses for stationary sources) , 2F ( Determination of*********E.O. 12866 Review**

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Page **180** of **208** Stack Gas Velocity and Volumetric Flow Rate With Three - Dimensional Probes) , 2H ( Determination of Stack Gas Velocity Taking Into Account Velocity Decay Near the Stack Wall) , 3A ( Determination of O 2 and CO 2 Concentrations in Emissions From Stationary Sources (Instrumental Analyzer Procedure)) , 3B ( Gas analysis for the determination of emission rate correction factor or excess air) , 4 ( Determination of Moisture Content in Stack Gases) , and 19 ( Determination of SO 2 Removal Efficiency and PM, SO 2 , and NOX Emission Rates) of 40 CFR part 60 . In addition , the EPA cites ASTM Methods D240 - 09 ( Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, for number 2 fuel oil heat content ) , D1826 - 94 (2010) ( Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, for natural gas heat content) , D4809 - 09a ( Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), for number 2 fuel oil heat content ) , D5287 - 08 ( Standard Practice for Automatic Sampling of Gaseous Fuels) , D4057 - 06 ( Standard Practice for Manual Sampling of Petroleum and Petroleum Products) , and D4177 - 95(2010) ( Standard Practice for Automatic Sampling of Petroleum and Petroleum Products). The EPA is proposing use of ANSI/ASME Method PTC 19.19 - 1981 as an acceptable alternative to EPA Method 3B .*********E.O. 12866 Review**

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Page **181** of **208** Consistent with the NTTAA, the EPA conducted searches to identify VCS in addition to the identified EPA methods. No appli cable VCS were identified for EPA Methods 2F, 2H, and 19 . The search and review results have been documented and are placed in the docket for this proposed rule. The search identified eight VCS that were potentially applicable for this rule in lieu of EPA reference methods. After reviewing the available standards, the EPA determined that the eight candidate VCS identified would not be practical due to lack of equivalency, documentation, validation data, and other important technical and policy consideratio ns. The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially- applicable VCS and to explain why such standards should be used in this action.*********E.O. 12866 Review**

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Page **182** of **208** List of Subjects in 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.

___________________ Dated:[add signature date]

____________________ Lisa P. Jackson, Administrator.*********E.O. 12866 Review**

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Page **183** of **208** For the reasons stated in the preamb le, title 40, chapter I, part 60 of the Code of the Federal Regulations is proposed to be amended as follows: **PART 60 --**  **[AMENDED]** 1. The authority citation f or 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 Utility Generating Units** Sec. **Applicability** §60.5508 What is the purpose of this subpart? §60.5509 Am I subject to this subpart? §60 .5510 What is the affected EGU of this subpart? **Emissions Standards** §60.5515 What greenhouse gases are regulated by this subpart? §60.5520 What CO 2 emissions standards must I meet? **General Compliance Requirements** §60.5525 What are my general requirements for complying with this

subpart? §60.5530 Affirmative Defense for Exceedance of Emission Limit During

Malfunction **Monitoring a nd Comp** **liance Determination Procedures** §60.5535 How do I monitor and collect data to demonstrate

compliance?*********E.O. 12866 Review**

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Page **184** of **208** §60.5540 How do I demonstrate compliance and determine excess

emissions with my CO 2 emissions limit?

**Notifications, Reports, and Records** 60.5550 What notifications must I submit and when? 60.5555 What reports must I submit and when? 60.5560 What records must I keep? 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 me? §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 fo r the control of greenhouse gas (GHG) emissions from electric utility generating units that commenced construction after [ INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER ] . **§60.5509 Am I subject to this subpart?**  You are subject to this subpart if you own or operate an electric utility generating unit that commences construction after [INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER] with a base load rating of more than 73 megawatts (MW) (250 million British thermal units per hour (MMBtu/h)) heat input of fuel . **§ 60.**  **5510 What is the affected source of this subpart?** *********E.O. 12866 Review**

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Page **185** of **208** (a) The affected facility to which thi s subpart applies is each electric utility generating unit (EGU) except as provided for in paragraph (b) of this section. (b ) An electric utility generating unit that meets the conditions specified in paragraphs (b)(1) through (b)(3) of this section is exempt from this subpart. ( 1 ) A steam electric generating unit that meets the definition of municipal waste combustor unit and is subject to subpart Eb of this part. ( 2 ) A steam electric generating unit that meets the definition of a commercial or industrial solid waste incineration unit and is subject to subpart CCCC of this part. (3) Transitional sources. (i) You are not subject to this subpart if you own or operate a transitional source that commences construction within 12 months after [ INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER ]. (ii) For purposes of this subsection, a “transition al source” is defined as an EGU with a base load rating of more than 73 megawatts (MW) (250 million British thermal units per hour (MMBtu/h)) heat input of fossil fuel, except as provided for in §60.5510(b)(1) and (2), and that received a complete permit that meets the*********E.O. 12866 Review**

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Page **186** of **208** requirements of the Prevention of Significant Deterioration Program under part C of Title I of the Clean Air Act prior to [ INSERT DATE OF THIS PROPOSED RULE IN THE FEDERAL REGISTER] . **Emissions Standards §60.**  **5515 What greenhouse gases are regu** **lated by this subpart?** The greenhouse gas regulated by this subpart is carbon dioxide (CO 2 ). **§60.5520 What CO** **2 emissions standards must I meet?**  (a) You must not discharge any gases that contain CO 2 from any affected EGU into the atmosphere in excess of 450 kilograms (kg) of CO 2 per gross output in Megawatt hours (MWh) (450 kg/MWh) on a 12
- operating month rolling average basis, except as provided for in paragraphs (b) through ( d ) of this section. (b) If the affected EGU is designed to allow installation and operation of a carbon capture and storage (CCS) system and you plan to do so at a time when such a system is commercially available for your affected EGU, you may elect to comply with both standards in paragraphs (b)(1) and (2) as an alternative to complyi ng with paragraph (a) of this section. (1) You must not discharge any gases that contain CO 2 from the affected EGU into the atmosphere in excess of 820 kg/MWh gross output on a 12 - operating month rolling average basis .*********E.O. 12866 Review**

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Page **187** of **208** (2) You must not discharge any gases that contain CO 2 from the affected EGU into the atmosphere in excess of 450 kg/MWh gross output on a 30 - year average basis . (c) If the affected EGU is located in a noncontinental area, you must not discharge any gases that contain CO 2 from any affected EGU into the atmosphere in excess of 630 kg/MWh gross output on a 12
- operating month rolling average basis . (d) S tationary combustion turbine with a federally enforceable permit limiting its operation to no more than 3 ,000 hours per calendar year are not subject to the requirements of this subpart . **General Compliance Requirements §60.**  **5525 What are my general requirements for complying with this**  **subpart?** (a) You must be in compliance with the emission s limit s in this subpart applicable to your affected EGU . These limits apply at all times. (b) At all times you must operate and maintain each affected EGU , including associated equipment and monitoring equipment, in a manner consistent with safety and good pract ices for minimizing CO 2 emissions. De termination of whether such operation and maintenance procedures are being used will be based on i nformation available to the Administrator which may include, but is not limited to, fuel use*********E.O. 12866 Review**

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Page **188** of **208** records, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, review of reports required by this subpart, and inspection of the facility . ( c ) For each affected EGU subject to the CO 2 emission s limit s in § 60.55 20, you must measure or calculate a 12 month rolling average CO 2 emission rate, calculated per calendar month, in terms of tons/MWh. (d) You must conduct an initial compliance determination for your affected EGU according to the requirements in this subpart within 30 days following the first day of the 13 th operating month following the date of initial operations. Thereafter, you must demonstrate continuous compliance according to the requirements in this subpart each calendar month determined to be an operating month. **§60. 5530**  **Affirmative Defense for Excee dance of Emission Limit During**  **Malfunction.** In response to an action to enforce the stan dards you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined at 40 CFR 60. 2. Appropriate penalties may be assessed, however, if the respondent fails to meet its burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief. (a) To establish the affirmative defense in any action to*********E.O. 12866 Review**

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Page **189** of **208** enforce such a limit, the owners or operators of facilities must timely meet the notification requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that: (1) The excess emissions: (i) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner; (ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and (iii) Did not result from any activity or event that could have been foreseen and avoided, or planned for; and (iv) Were not part of a recurring pattern indicative of inadequate design , operation, or maintenance; (2) Repairs were made as expeditiously as practicable when the applicable emission l imitations were being exceeded. Off - shift and overtime labor were used, to the extent practi cable to make these repairs; (3) The frequency, amount and durat ion of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; (4) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to p revent*********E.O. 12866 Review**

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Page **190** of **208** loss of life, personal injury , or severe property damage; (5) All practicable steps were taken to minimize the impact of the excess emissions on ambient air quality, the e nvironment and human health; (6) All emissions monitoring and control systems were kept in operation if at all practicable , consistent with safety and good air pollution control practices; (7) All of the actions in response to the excess emissions were documented by properly signed, con temporaneous operating logs; (8) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions; and (9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction. (b ) The owner or operator of an affected EGU experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as
soon as practicable , but no later than two (2) business days after the initial occurren ce of the malfunction, if it wishes to avail*********E.O. 12866 Review**

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Page **19 1**  of **208** itself of an affirmative defense to civil p enalties for that malfunction. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the Administrator within 45 days of the initial occurrence of the exceedance of the standard to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section. The owner or operator may seek an extension of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 - day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedances.

**Monitoring a nd Comp** **liance Determination Procedures §60.**  **5535 How do I monitor and collect data to demonstrate compliance?**  (a) You must p repare a site - specific monitoring plan that addresses the monitoring system design, data collection and the quality assurance and quality control elements consistent with the applicable requirements in §60. 13, 40 CFR part 75, and this section. (b) Follow the applicable quality assurance procedures for CO 2 emissions in appendices B, D, and G to 40 CFR part 75. (c) If you determine the your affected EGU’s CO 2 mass emissions rate by monitoring fuel combusted in the affected EGU and periodic*********E.O. 12866 Review**

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Page **192** of **208** fuel sampling as al lowed under §60.5525(c)(2), you must use the procedures specified in 40CFR Part 75, Appendix G. (1 ) Determine a site - specific F factor using the ultimate analysis and GCV in equation F - 7a of 40 CFR part 75, Appendix F; and (2 ) Monitor and determine the affected EGU’s daily fuel consumption for each type of fuel combusted in the affected EGU. (d) You must monitor and record the applicable data needed to and determine your affected EGU’s gross output for each operating month. ( e) Follow the applicable missing data substitution procedures in 40 CFR part 75 for CO 2 concentration, stack gas flow rate, fuel flow rate, high heating value, and fuel carbon content. **§60. 5540**  **How do I demonstrate compliance and determine excess**  **emissions with my CO** **2 emissions limit?**  (a) If you use a CO 2 CEMS to demonstrate compliance You must use the procedure specified in paragraphs (a)(1) through (5) of this section to determine the 12 - operating month rolling average CO 2 emissions rate for your affected EGU. (1) Calculate hourly CO 2 mass emissions for each hour of the operating month in terms of kilograms CO 2 using CFR 40 Part 75 Appendix G. (2) Determine hourly gross output in terms of MWh for each hour*********E.O. 12866 Review**

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Page **193** of **208** of the operating month. (3) Sum the hourly CO 2 mass emissions for the operating month, and sum the hourly gross output for the operating month. (4) Divide the total CO 2 mass emissions calculated for the month by the total hourly gross output calculated for the operating month. (5) Add the quotient to the sum of the quotients of the previous 11 operating months to determine the 12 - operating month rolling average. (6) If the 12 - operating month rolling average value does not exceed the applicable emissions limit in §60.5520 , your affect ed EGU is determined to be in compliance with the emissions limit. Otherwise, your affected EGU is determined to have excess emissions. ( b ) If you use fuel sampling to demonstrate compliance, you must use the procedure specified in paragraphs (b)(1) through (5) of this section to determine the 12 - operating month rolling average CO 2 emissions rate for your affected EGU. (1) Calculate monthly CO 2 mass emissions by multiplying the monthly F factor by the monthly fuel consumption. (2) Sum the hourly gross outpu t in terms of MWh for the month. ( 3 ) Divide the monthly CO 2 mass emissions by the sum of the hourly gross output for the month. (4 ) Add the quotient to the sum of the quotients of the previous*********E.O. 12866 Review**

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Page **194** of **208** 11 operating months to determine the 12 - operating month rolling average. (5) If the 12 - operating month rolling average value does not exceed the applicable emissions limit in §60.5520 , your affected EGU is determined to be in compliance with the emissions limit. Otherwise, your affected EGU is determined to have excess emissions. (c) If you elect to comply with §60.5520 (b), the 30 - year average CO 2 emissions rate for your affected EGU is the sum of the monthly CO 2 emissions for each operating month for the 30 - year period divided by the sum of the monthly gross output in terms of MWh for the 30 - year period. **Notification, Reports, and Records §**  **60.5550 What notifications must I submit and when?**  (a) You must prepare and submit notifications specified in §60.7 (a) and §60.19, as applicable to your af fected EGU . (b ) You must prepare and submit notifications specified in 40 CFR part 75.61, as applicable to your affected EGU . **§60. 5555**  **What reports must I submit and when?** (a) You must prepare and submit reports specified in §60.7 (c) through (e) and §60.19 , as applicable to your affected EGU . All hard copy reports required under §60.7 must be postmarked by the 30th day following the end of each 6 -month period.*********E.O. 12866 Review**

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Page **195** of **208** (b ) You must follow the applicable reporting requirements and submit reports as required in subpart G of 40 CFR part 75 . You must report CO 2 mass emissions data, and other related data electronically using the Emissions Collection and Monitoring Plan System ( ECMPS). **§60. 5560**  **What records must I maintain?** (a) You must maintain records of your information used to demonstrate compliance with this subpart as specified in §60.7 (b) and (f). (b ) You must follow the applicable recordkeeping requirements and maintain records as required in subpart F of 40 CFR part 75 . (c) If you determine the CO 2 mass emissions rate by monitoring fuel combusted in an affected EGU and periodic fuel sampling according to the requirements in this rule then you must maintain records of fue l type and quantity combusted in the affected EGU for each operating month the information specified in paragraphs (c) (1) and (2 ) of this section. (1) Records of fuel type and quantity combusted in the affected EGU for each operating month. (2 ) Records of the calculations performed to determine the site specific F factor and monthly total CO 2 mass emissions rates. (d) Records of the applicable data recorded and calculations performed used to determine your affected EGU’s gross output for each*********E.O. 12866 Review**

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Page **196** of **208** operating month. **§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 expe ditious review . (b) You must keep each record for 5 years following the date of each occurrence, measurement, mainte nance, corrective action, report, or record except those records required to demonstrate compliance with the emissions limits in §60 .5520(b). Records required to demonstrate compliance with the emissions limits in §60 .5520(b) must be kept for at least 35 years following the date of initial startup of the affected EGU. (c) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, rep ort, or record, according to §60.10 . You can keep the
records off site for the remaining years as required by this subpart . **Other Requirements and Information §60.5570**  **What parts of the General Provisions apply to me?** Table 1 to this subpart shows which parts o f the General Provisions in §§60.1 through 60.19 apply to you. **§60.5575 Who implements and enforces this subpart?**  (a) This subpart can be implemented and enforced by EPA, or a delegated authority such as your state, local, or tribal agency. If*********E.O. 12866 Review**

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Page **197** of **208** the Administrator has delegated authority to your state , local, or tribal agency, then tha t 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 de legating implementation and enforcement authority of this subpart to a state, local, or tr ibal agency , the authorities listed in paragraphs (b)(1) through (5 ) of this section are retained by the Administrator and are not transferred to the state, local, or t ribal agency; however, 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 wil l have the meaning given them in the Clean Air Act and in subpart A (General Provisions of this part. Affirmative defense means, in the context of an enforcement*********E.O. 12866 Review**

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Page **198** of **208** proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding. Base load means the maximum amount of heat input ( fuel ) that a steam generating unit can combust on a steady state basis, as determined by the physical design and characteristics of the steam generating unit at ISO conditions. For a stationary combustion turbine base load means 100 percent of the design heat input capacity of the stationary combustion turbine engine at ISO conditions. Carbon capture and storage (CCS) means a process that includes capture and compression of CO 2 produced by an electric utility generating unit before re lease to the atmosphere ; transport of the captured CO 2 (usually in pipelines); and storage of that CO 2 in geologic formations, such as deep saline formations, oil and gas reservoirs, and unmineable coal seams. Coal means all solid fuels classified as anthr acite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporat ed 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*********E.O. 12866 Review**

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Page **199** of **208** natural gas), coal - oil mixtures, and coal -water mixtures are included in this defin ition 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 means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit. Combined heat and power , also known as “ cogeneration ,” means a steam- generating unit that simultaneously produces both electric (and mechanical) and useful thermal energy from the same primary energy source. Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply with the sp ecifications for fuel oil numbers 1 and 2, as defined by the American 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 AS TM D975 (incorporated by reference, see §60.17), kerosene, as defined 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*********E.O. 12866 Review**

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Page **200** of **208** in ASTM D675 1 (incorporated by reference, see §60.17), or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see §60.17). Electric utility generating unit or EGU means any steam electric generating un it or stationary combustion turbine that is constructed for the purpose of supplying more than one - third of its potential electric output capacity and more than 25 MW net - electrical output to any utility power distribution system for sale. Also, any steam supplied to a steam distribution system for the purpose of providing steam to a steam- electric generator that would produce electrical energy for sale is considered in determining the electrical energy output capacity of the affected EGU . Excess emissions means a specified averaging period over which the CO 2 emissions rate are higher than the applicable emissions standard. Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24. Fossil fuel mean s natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the*********E.O. 12866 Review**

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Page **201** of **208** purpose of creating useful heat. Gaseous fuel means any fuel that is present as a gas at standard conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke - oven gas, s ynthetic gas, and gasified coal. Gross output means the gross useful work performed is the gross electrical or mechanical output from the unit plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e. , steam delivered to an industrial process). Integrated gasification combin ed cycle electric utility generating unit means an electric utility combined cycle gas turbi ne 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 or repair. No solid fuel is directly burned in the unit during operation. ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure.*********E.O. 12866 Review**

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Page **202** of **208** 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. In addition, natural gas contains 20.0 grains or less of total sulfu r per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal - derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value . Net - electric output means the gross electric sales to the utility power distribution system minu s purchased power on a calendar year basis. Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands. Operating month means a calendar month during which any fuel is combusted in the electric utility generating unit at any time. Out - of- control period means any period beginning with the quadrant corresponding to the completion of a daily calibration error, linearity check, or quality assurance audit that indicate s*********E.O. 12866 Review**

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Page **203** of **208** that the instrument is not measuring and recording within the applicable performance specifications and ending with the quadrant corresponding to the completion of an additional calibration error, linearity check, or quality assurance audit following cor rective action that demonstrates that the instrument is measuring and recording within the applicable performance specifications. Potential e lectric o utput for a steam electric generating unit means 33 percent of the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/ yr ( e.g. , a steam generating unit with a 100 MW (340 MMBtu/h) fossil
- fuel heat input capacity would have a 289,080 MWh 12 month potential electrical output capacity). For a stationary combustion turbine potential e lectric o utput means 50 percent of the maximum design heat input capacity of the stationary combustion turbine , divided by 3,413 Btu/ kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/ yr ( e.g. , a stationary combustion turbine with a 100 MW (340 MMBtu/h) fossil
- fuel heat input capacity would have a 438 ,0 0 0 MWh 12 month potential electrical output capacity). 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*********E.O. 12866 Review**

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Page **204** of **208** limited to, coal, biomass, and pulverized solid fuels. Stationary combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post
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 combin ed heat and power combustion turbine based system. 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. Steam electric generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil - fuel - fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included) plus any integrated device that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment. Useful thermal output means the thermal ene rgy made available for use in any industrial or commercial process, or used in any he ating or cooling application, i.e., total thermal energy made*********E.O. 12866 Review**

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Page **205** of **208** available for processes and applications other than ele ctrical generation or to enhance the performance of the stationary combustion turbine. Thermal output for this subpart means the energy in recovered thermal output measured against the energy in the thermal output at ISO conditions .*********E.O. 12866 Review**

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Page **206** of **208***********E.O. 12866 Review**

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Page **207** of **208** Table 1 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 §60.5 Determination of

construction or modification Yes §60.6 Review of plans Yes §60.7 Notification and

Recordkeeping Yes §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*********E.O. 12866 Review**

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Page **208** of **208** §60.13 Monitoring

requirements Yes §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