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Page **1** of **233 ENVIRONMENTAL 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 ca rbon dioxide (CO 2 ) for new affected fossil - fuel - fired electric utility generating units (EGUs). The EPA is proposing these requirements because CO 2 is a greenhouse gas (GHG) and fossil - fuel - fired power plants are the country’s largest stationary source emi tters of GHGs. 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 n output - based standard of 1,000 pounds of CO 2 per megawatt - hour, based on the performance of widely used natural gas combined cycle (NGCC) technology. New coal - fired units could meet the standard**02/2 8** **/2012 Draft**

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Page **2** of **233** either by employing carbon capture and storage (CCS) 1 of approximately 50% of the CO 2 in the exhaust gas at startup, or through later application of more effective CCS to meet the standard o n average over a 30 - year period. The thirty year averaging option could also provide flexibility for owners and operators of coal units with CCS that achieved greater than 50% reductions to address startup concerns or short term interruptions in their ability to sequester captured carbon dioxide. The EPA is not proposin g standards of performance for existing EGUs whose CO 2 emissions increase as a result of installation of pollution controls for 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 result, those sources would not be subject to the standards of performance proposed in today’s rule. At a future date, the EPA inten ds to promulgate emission guidelines for states to develop plans reducing CO 2 emissions from existing fossil - fuel - fired

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 ‘sequestrati on’ mean the same thing and the words are used interchangeably.**02/2 8** **/2012 Draft**

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Page **3** of **233** EGUs. **DATES:** Comments . Comments must be received on or before [INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REG ISTER 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 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 receives 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 x public hearings on this proposal. The dates, times, and locations of the public hearings will be announced separately. 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 in 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**02/2 8** **/2012 Draft**

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Page **4** of **233** notify Ms. Garrett at least 2 days in advance of the public hearings. The p ublic 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 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 informa tion 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 comments by electronic mail (e - mail) to a - and r - docket@epa.gov , Attn: Docket ID No. EPA - HQ - OAR - 2011 - 0660. Facsimile : Fax your comments to (202) 566 - 9744, Attn: Docket ID No. EPA - HQ - OAR - 2011 - 0660 .**02/2 8** **/2012 Draft**

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Page **5** of **233** Mail : Send your comments to the EPA Docket Cente r, U.S. EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 20460, Attn: Docket ID No. EPA - HQ - OAR - 2011 - 0660 . Please 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, 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, Wa shington, 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 mad e 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 information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do no t submit information that**02/2 8** **/2012 Draft**

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Page **6** of **233** you consider to be CBI or otherwise protected through http://www.regulations.gov or e - mail. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404 - 02), Of fice 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 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 informa tion claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion 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 FURTHER INFORMATION CONTACT).**  If the comment includes information you consider to be CBI or otherwise protected, a copy of the comment t hat does not contain the information claimed as CBI or otherwise protected should be sent.**02/2 8** **/2012 Draft**

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Page **7** of **233** 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 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 techn ical 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 publicly available (e.g., CBI or other information whose disclosure is restricted by statute). Certain other material, such as copyrigh ted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW,**02/2 8** **/2012 Draft**

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Page **8** of **233** Was hington, 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. Vi sit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm for additional information about the EPA’s public docket. In addition to being available in the docket, an electronic copy of this proposed rule will also be available on the Wor ldwide 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/o arpg/ . 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 Tria ngle 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.**02/2 8** **/2012 Draft**

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Page **9** of **233 SUPPLEMENTARY INFORMATION:**  Acronyms . A number of acronyms are used in this preamble. While this may not be an exhaustive list, to ease the readi ng 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 ASME American Society of Me chanical Engineers ASTM American Society for Testing of Materials BSER Best System of Emission Reduction Btu/kWh British Thermal Units per Kilowatt Hour Btu/lb British Thermal Units per Pound CAA Clean Air Act CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration) CEMS Continuous Emissions Monitoring System CH 4 Methane CHP Combined Heat and Power CO 2 Carbon Dioxide CSAPR Cross - State Air Pollution Rule DOE Department of Energy DOT Department of Transportation ECMPS Emissions Collection and Monitoring Plan System EERS Energy Efficiency Resource Standards EGU Electric Utility Generating Units EIA Energy Information Administration EO Executive Order EOR Enhance Oil Recovery EPA Envi ronmental Protection Agency FR Federal Register GHG Greenhouse Gas H 2 Hydrogen Gas HAP Hazardous Air Pollutant HFC Hydrofluorocarbon HRSG Heat Recovery Steam Generator IGCC Integrated Gasification Combined Cycle IPCC Intergovernmental Panel on Climate Change IPM Integrated Planning Model**02/2 8** **/2012 Draft**

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Page **10** of **233** kg/MWh Kilogram per Megawatt - hour kJ/kg Kilojoules per Kilogram kWh Kilowatt Hour lb CO 2 /MMBtu Pound of CO 2 per Million British 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 N ational Ambient Air Quality Standards NAICS North American Industry Classification System NAS National Academy of Sciences NETL National Energy Technology Laboratory NGCC Natural Gas Combined Cycle 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 Particulate Matter PM 2.5 Fine Particulate Matter PRA Paperwork Reduction Act PSD Prevention of Significant Dete rioration 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 Social Cost of Carbon SF 6 Sulfur Hexafluoride SIP State Implementation Plan SO 2 Sulfur Dioxide SSM Startup, Shutdown, and Malfunction Tg Teragram Tpy Tons per Year TSD Technical Support Document**02/2 8** **/2012 Draft**

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Page **11** of **233** TTN Technology Transfer Network TVA Tennessee Valley Autho rity UIC Underground Injection Control UMRA Unfunded Mandates Reform Act of 1995 U.S. United States USGCRP U.S. Global Climate Research Program VCS Voluntary Consensus Standard WWW Worldwide Web Organization of This Document . The information p resented in this preamble is organized as follows: I. General Information 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 emissions 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 requirements? G. What are the notification, recordkeeping, and reporting requirements? IV. Rationale for the Proposed S tandards: 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 T itle V Program VI. Discussion of Modified Sources A. CAA Section 111 Requirements B. Timing for Promulgation of Standards of Performance for Modifications**02/2 8** **/2012 Draft**

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Page **12** of **233** 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. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Ris ks 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 Popu lations 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. In 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 emission s than any other stationary source**02/2 8** **/2012 Draft**

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Page **13** of **233** category in the United States, and among new GHG emissions sources, the largest individual sources are in this source category. This rulemaking proposes federal standards of performance for new fossil fuel - fired power pla nts that can be met with existing technology. Note that in this preamble, while we refer to these sources, interchangeably, as power plants, steam generating units, affected sources, fossil - fuel - fired electric generating units, covered EGUs, or, simply, E GUs, the proposed standards apply to only those sources identified in Section III.A. as the affected source 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 emissio ns, which by causing climate change, pose a serious threat to public health and welfare. The EPA is focusing first on reducing emissions from the largest emitters through measures with reasonable costs. The EPA is proposing to control CO 2 pollution from fo ssil - fuel - fired power plants because they are responsible for approximately 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 exist s that can be readily and cost -
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.**02/2 8** **/2012 Draft**

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Page **14** of **233** effectively used to reduce GHG emissions from fossil - fuel - fired power plants . Thus, this proposed rule is a rational first step to control GHG emissions from the largest - emitting 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) of the N ational Academies 3 stated in a 2011 report, “Each additional ton of greenhouse gases emitted commits us to further change 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

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, B oard 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 .**02/2 8** **/2012 Draft**

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Page **15** of **233** 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 year s. 6 Based on the Endangerment Finding and its underlying TSD 7 , reasons to reduce GHG emissions include the following:

 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, increased 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.

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 Endangerment an d 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.**02/2 8** **/2012 Draft**

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Page **16** of **233**  These effects are anticipated to result in premature deaths, illnesses, damage to property and infrastructure, 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 impact s can be quantified. 9

 A supporting consideration is that climate change impacts in certain regions of the world (potentially leading for example to food scarcity, conflicts or mass migration) may exacerbate problems that raise humanitarian, trade and natio nal 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

8 Endangerment Finding, 74 FR 66498. 9 Endangerment Finding, 74 6 6497. 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**02/2 8** **/2012 Draft**

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Page **17** of **233** 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 adapt ing to them. 13 Examples include severe drought in subtropical areas, release of large amounts of GHGs stored in the sea floor and frozen Arctic soils, 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 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 reduc tion 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
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 15 National Research Council (NRC) (2011). Climate Stabilization Targets. Committee on Stabilization Targets for Atmospheric**02/2 8** **/2012 Draft**

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Page **18** of **233** longer that the U.S. and other countries take to reduce emissions, the steeper the futu re 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 risks. 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 Power Plants and the Opportunities to Reduce these Emissions. Fossil - fuel fired power plants comprise the largest category of stationary source GHG emissions in the U.S. These sources account for 60 p ercent 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.
Greenhouse Gas Concentrations; Boa rd on Atmospheric Sciences and Climate, Division of Earth and Life Sciences, National Academy Press. Washington, DC. 16 “Inventory of US GHG Emissions and Sinks” (April 2011); “Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissio ns Final Rule (GHG Reporting)” (September 2009).**02/2 8** **/2012 Draft**

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Page **19** of **233** today are eithe r 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 t heir CO 2 emissions per MWh generated to levels similar to, or even lower than, those of natural gas - fired combined cycle plants without CCS. Coal - fired power plants with CCS are being permitted and built today , albeit with considerable financial assistance from the federal government . 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 i s efficient because the EPA has 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 gives the industry mo re regulatory certainty, will**02/2 8** **/2012 Draft**

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Page **20** of **233** 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 proposed 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 Ameri can 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 pa th forward ... We are clearly in a classic ‘which comes first?’ situation. The commercialization of this technology is vital if owners of coal - fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, c ost - 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**02/2 8** **/2012 Draft**

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Page **21** of **233** 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 Massachuse tts 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 emissions. As a result of this decision, the EPA obtained a voluntary
re mand from the U.S. Court of Appeals for the District of Columbia Circuit (the “Court”) to reconsider the EPA’s actions in a 2006 rulemaking for EGUs under CAA section 111, in which the EPA had promulgated 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 from new EGUs. 4. Legal Basis for CAA Standard s for Fossil - Fi red Power Plants a. General Legal Requirements. Clean Air Act section 111 establishes a several - step process for the EPA and the states to regulate air pollutants from stationary sources. First, the EPA must list alread y in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share.” 19 549 U.S. 497 (2007).**02/2 8** **/2012 Draft**

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Page **22** of **233** categories of stationary sources that cau se 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 account ... cost [and other factors]) ... has been adequately demon strated.” 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 Ai r 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 the 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 appr oval.**02/2 8** **/2012 Draft**

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Page **23** of **23 3**  The 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 re asonably 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 regulations under CAA section 111. Subsequent regulation of utility boilers h as been under subpart Da. The EPA listed combustion turbine engines and initially regulated them under subpart GG. The combustion turbine engine portions of combined cycle facilities were regulated under subpart GG. Heat recovery steam generators associate d 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 steam generator. To minimize the compliance burden for own ers/operators of combined cycle facilities some monitoring harmonization was done, but 2 subparts were still applicable. In 2005, the EPA proposed subpart KKKK as a replacement**02/2 8** **/2012 Draft**

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Page **24** of **233** for subpart GG and specifically covered the entire combined cycle facility unde r subpart KKKK such that only a single set or requirements would apply. In that same year, the EPA proposed to include Integrated Gasification Combined Cycle (IGCC) facilities under the applicability of subpart Da. The EPA is authorized to promulgate the r ulemaking 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 interpreted 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 endange r 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**02/2 8** **/2012 Draft**

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Page **25** of **233** Endangerment Finding, along with the EPA’s 2010 acti on denying 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 emis sions 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 t he EPA base its regulation of CO 2 emissions from EGUs on a rational basis for protection 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 Sciences’ 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**02/2 8** **/2012 Draft**

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Page **26** of **233** 5. Summary of Today’s Proposed Requi rements to Reduce GHG Emissions from New Fossil - Fired Power Plants , and Rationale for those requirements a. Summary of Proposed Revisions to Categories and Requirements for New Sources i. Revisions to Categories of EGUs. In today’s action, the EPA is pr oposing 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 electricity for sale and meet certain size criteria (which are currently in cluded 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 simple cycle turbines. 21 ii. Control Requirements for New Sources. The EPA is proposing stan dards 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 g as 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.” 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.**02/2 8** **/2012 Draft**

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Page **27** of **233** combined cycle (NGCC) units, which are currently in wide use throughout the country. Coal - , 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 p et - 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 expect the difference to decrease over time as CCS becomes less expensive. Accordingly, w e include in today’s proposed rulemaking an alternative 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 al ternative must meet an immediate performance standard of 1,800 lb CO 2 /MWh (gross ) on a 12 - month rolling average basis, which can be achieved by a “supercritical” efficiency level, during the period before installation of CCS. By no later than the 11 th year, the facility would be required to meet a reduced emission limit of no more than 600 lb CO 2 /MWh (272 kg CO 2 /MWh) (gross) on a 12
- month rolling average basis for the remaining 20 years of the 30 - year period, such that the weighted average CO 2 emissi ons rate from the facility over the 30 - year time period would be equivalent to the**02/2 8** **/2012 Draft**

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Page **28** of **233** proposed standard of performance of 1,000 lb CO 2 /MWh. We seek comment on an alternative mechanism for establishing practicably enforceable short term limits during the 30 - ye ar period, requiring the owner/operator to identify and obtain approval of, at the time of construction, an alternative 30 - year emission trajectory, specifying the emission rate for each year during the 30 - year period consistent with meeting a 30 - year aver age emission rate of 1,000 lb CO 2 /MWh; 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. b. Rationale . Today’s proposal to combine the relevant parts of the Da and KKKK categories is authorized under CAA section 111(b)(1)(A) because that provision authorizes the EPA, after drawing up the list of affected source categories, to “revise” that list from time to time. Combining the relevant parts of the categories, as the EPA proposes to do, is one method to “revise” the list. Moreover, the EPA’s action to combine is reasonable because with the combination, all new fossil - fuel - fired electricity generating units ( and that meet specified minimum criteria) will be subject to the same requirements, and therefore will be treated alike because they function alike. The EPA is not including simple cycle turbines in this rule, because they generally operate differently tha n the other units covered by today’s**02/2 8** **/2012 Draft**

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Page **29** of **233** rule. The units covered by today’s rule are generally used for base load or intermediate power generation, while simple cycle turbines are generally used much less often (and thus have low GHG emissions) and are used to meet peak rather than base or intermediate load requirements. Today’s proposal to require an emission rate of 1,000 lb CO 2 /MWh meets the requirements for a “standard of performance,” as defined under CAA section 111(a)(1). This proposed standard is based on the degree of emission limitation achievable through natural gas combined cycle (NGCC). NGCC qualifies as the “best syst em of emission reduction” (BSER) that the EPA has determined has been adequately demonstrated because NGCC emits the least amount of CO 2 and does so at the least cost. The just - described reasons are sufficient as a legal matter to justify today’s propose d actions to combine source categories and establish the 1,000 lb CO 2 /MWh standard. Such a standard could also be met today by coal - fired units using CCS. In addition, we propose to include the compliance alternative of allowing coal - fired power plants to meet either the 1000 CO 2 /MWh standard or to meet this standard over a 30 - year period so that plant developers can take advantage of potential advancements in CCS technology that could lower prices or so that they can have the operational flexibility to**02/2 8** **/2012 Draft**

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Page **30** of **233** ins tall CCS when the unit commences operation but optimize it and address any startup challenges related to issues such as business arrangements related to sequestration of CO2 . We recognize that in light of the increased availability and significantly lower price of natural gas, energy industry modeling forecasts uniformly predict that few, if any, new coal - fired power plants will be built in the foreseeable future. Therefore, for these economic reasons, the new source component of the fossil - fuel - fired elect ricity generating industry is in effect restructuring towards gas and away from coal. Today’s proposed action is consistent with that trend, and in no way could be considered a cause of that trend. We recognize that some owners/operators may nevertheless seek to construct new coal - fired capacity. This may be beneficial from the standpoint of promoting energy diversity, and today’s proposal does not interfere. In the first instance, a new coal - fired power plant may be able to meet the 1,000 lb CO 2 /MWh stand ard by installing CCS at the time of construction. At present, CCS would add considerably to the costs of a coal - fired power plant, but there are some sources of funding available through a limited number of government pilot programs. Because modeling fore casts construction of no more than a few coal - fired power plants under any circumstances, those few may well have access to those government pilot programs.**02/2 8** **/2012 Draft**

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Page **31** of **233** The proposed 30 - year compliance option adds additional flexibility for coal - fired power plants by a llowing them to construct and begin operations, and then install CCS at some time in the future, as long as they install CCS at a time and in a manner that allows them to meet the 1,000 lb CO 2 /MWh standard over the 30
- year period. We expect that the costs of CCS will decline in the future as CCS is utilized more widely. Today’s action, if finalized, would promote utilization of CCS by making clear that CCS is required for coal - fired power plants. The prospect of declining CCS costs, in conjunction with the possibility of continued availability of additional funding mechanisms (e.g. pilot funding such as DOE grants, t a x credits for investment or EOR and state incentives such as c lean
e nergy standards), indicates that CCS may be sufficiently accessible in the near future to the few coal - fired power plants that could be expected to construct. Thus, the 30 - year compliance option, along with the current opportunities for funding to install CCS immediately, counters any concerns that today’s action could restrict new coal - fired construction. It should be noted that we are not required to justify the 30 - year average compliance alternative on grounds that it qualifies as the “best system of emission reduction” adequately demonstrated, and**02/2 8** **/2012 Draft**

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Page **32** of **233** we are not stating in this a ction whether that compliance alternative does or does not qualify as such. Thus, it is not necessary to determine that our expectation that costs will go down meets the standards for determining that CCS is “adequately demonstrated.” Rather, to reiterate , the 30 - year compliance alternative, along with the opportunities to install CCS immediately, make clear that CCS remains sufficiently available for the limited number of coal - fired power plants that may newly construct to serve the policy goals of promot ing energy diversity. 22 Indeed, by clarifying that in the future, new coal - fired power plants will be required to install CCS, this rulemaking eliminates uncertainty about the status of coal and may well enhance the prospects for new coal - fired generation, and thereby promote energy diversity. c. Requirements for Modifications , and Rationale. For purposes of today’s action, the EPA does not have a sufficient base of information to develop a proposal for the relatively few affected
sources that may be expected to take actions that would constitute “modifications” (as defined under the EPA’s NSPS regulations) and therefore be subject to requirements for new sources. As a result, the EPA is not proposing requirements for NSPS modifications.

22 EIA analysis (AEO 2012 early release) shows that “coal remains the dominant energy source for electricity generation . ”**02/2 8** **/2012 Draft**

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Page **33** of **233** The EPA’s current regulations define an NSPS “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 control projects, which are pr ojects that entail the installation of pollution control equipment or systems. The significant majority of projects that we believe EGUs are most likely to undertake in the foreseeable future that could increase the maximum achievable hourly r ate of CO 2 emissions would constitute pollution control projects. In many cases, those projects would involve the installation of add - on control equipment required to meet CAA requirements for conventional air pollutants. These increases in CO 2 emi ssions would generally be small and would occur as a chemical byproduct of the operation of the control equipment. In other cases, those projects would involve equipment changes to improve efficiency to meet the requirements of a future 11 1(b) rulemaking for existing
sources and would have the effect of increasing a source’s maximum achievable hourly emission rate (lbs CO 2 /hr), even while decreasing its actual output based emission rate (lbs CO 2 /MWh). Because all of these actions would be treated as pollution control projects under the EPA’s current NSPS regulations, they would be specifically exempted from the definition of modification .**02/2 8** **/2012 Draft**

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Page **34** of **233** In the past, there have been a small number of instances, on appro ximately an annual basis, in which power plants have undertaken actions that , in the EPA’s view, should be treated as modifications. The sources that took these actions vary widely one from another, and the types of actions were disparate. In light of this, we do not have adequate information as to the types of actions that qualify as modifications, the amount of increase in CO 2 emissions they cause, the types of control measures, or the costs and effectiveness of control
measures , on which to base a proposed standard of performance. Therefore, in today’s action, we are not proposing a standard of performance for modifications. As a result, sources that undertake modifications will be treated as existin g sources and thus not subject to the requirements proposed in this notice, although they would be subject to requirements that the EPA intends to propose separately for existing EGUs. In today’s action, we solicit comment on the types of modifications power plants undertake and appropriate control measures. Depending on the information we develop, we may issue proposed standards of performance in the future . d. Requirements for Transitional sources. The EPA is aware that approximately 1 5 proposed EGUs have received CAA permitting authority approval for their preconstruction permits, but may not have**02/2 8** **/2012 Draft**

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Page **35** of **233** “commenced construction” by the date of today’s proposed rulemaking. A few of these sources have taken additional action preparatory to
commencing construction. For this proposed rule, these sources that, as of the date of this proposal, have a PSD permit and are poised to commence construction within the very near future are referred to as “transitional sources.” We are aware that approximate ly seven of these permitted sources are permitted to implement CCS to some degree. CAA section 111 provides by its terms that sources that have not “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 construction or entering into a binding contract to do so. 40 CFR 60.2. Commenters 23 have pointed out that absent different treatment , transitional sources will be subject to the same requirements that apply to new sources that did not obtain their permit before the date of proposal, and these commenters have suggested that today’s

23 As mentioned elsewhere, the EPA held a series of listening sessions and allowed for a period of additional comment after announcing it was moving forward with development of new source performance standards for GHGs emitted from fossil fuel - fired EGUs. The term “commenters” here refers to those who commented during the listening sessions or during the subsequent comment period.**02/2 8** **/2012 Draft**

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Page **36** of **233** proposed rule sh ould 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
s ources at issue are coal - fired EGUs that, absent special treatment, 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 , which we define as sources that a PSD permit by the date of this proposal and 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 date of this proposed action will be subject to the standard of performance for new sources.**02/2 8** **/2012 Draft**

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Page **37** of **233** e. Requirements for Reconstructed sources , and Rationale. The EPA’s CAA section 111 regulations provide that reconstructed sources are to be treated as new sources an d, 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 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. Historically, we believe that very few power plants have undertaken reconstructions. The EPA is not aware that any power plants are presently planning any project that could meet the requirements for a reconstruction. In light of this limited experience concerning reconstructions, we lack adequate information about the type of source; the type of changes; the extent of emissions increases; and the type of control measures, including their cost and emis sions reductions, that we need to propose a standard of performance for reconstructions, and we solicit comment on these issues. As a result, in today’s action, the EPA is not including a proposal for reconstructions and instead is soliciting comment on two different options. Under the first, we would not promulgate a**02/2 8** **/2012 Draft**

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Page **38** of **233** standard of performance concerning reconstructions when we finalize this action, but, depending on the information we receive, we may propose and finalize such a standard at a later time. Un der the second option, we would finalize a standard of performance. Under one sub - option, we would finalize a standard of 1,800 lb CO 2 /MWh (gross). This would be consistent with the first phase requirement for new sources availing themselves of the 30 - year alternative compliance option. It would represent upgrading the unit to an efficiency level consistent with some of the best performing existing units. A second sub - option 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). This sub - option could be based on the view 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 purpos e would be to avoid creating an incentive for an owner to forego building a new clean facility, in favor of merely reconstructing an existing facility that operated with higher emissions . 6. Summary of Emissions Impacts, Costs and Benefits We are projecting that there will be no construction of new coal fired generation without CCS even absent this proposed rule. In addition to looking at a primary case consistent with EIA’s primary**02/2 8** **/2012 Draft**

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Page **39** of **233** case assumptions for electric demand, we also looked at a case with higher electric demand and another case with higher natural gas prices. We did not see any additional coal builds th rough 2030 in either of these cases. We also looked at a case with both increased natural gas prices and increased electric demand. In this case we saw small amounts of coal being built in 2030. Because we did not see any new coal builds in 2020 in any of the cases examined and we only saw small amounts of coal in the most extreme case examined in 2030 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 greenhous e 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. Internati onally, 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.

**Table 1. Potentially Affected Entities a**  **Category NAICS** 

**Code Examples of Potentially Regulated**  **Entities 02/2** **8 /2012 Draft** 

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Page **40** of **233** 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 (including boilers and stationary combined cycle combustion turbines). b Federal, state, or local government - owned and operated establishments are classifi ed 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, bu siness, 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 applicability of this action to a particular entity, consult either the air permit ting 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 02/2** **8 /2012 Draft** 

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Page **41** of **233** A. Statutory Background for this Rule Clean 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 stationary sources that the Administrator, in his or her judgment, finds “cause[], or contribute[] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” 24 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 unde rtake 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 provisions 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 ai r pollutant not previously emitted.” CAA section 111(a)(4). The EPA’s NSPS regulations provide exemptions for several types of changes, including the installation of pollution control

24 The EPA has made endangerment findings under this section for more than 60 stationary source categories and subcategories that are now subject to NSPS.**02/2 8** **/2012 Draft**

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Page **42** of **233** 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 costs of the new equipment or components exceed 50 percent of what is believed to be the cost of a completely new facility. 40 CFR 60.15. In promulgating standards of performance, the EPA has significant discretion to create subcategories based on source type, class or size. CAA section 111(b)(2). Clean Air Act section 111(a)(1) defines a “standard of performance” as

– a standard for emissions of air pollutants which reflects the de gree 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 Admi nistrator determines has been adequately demonstrated. We call this level of control the best system of emission reduction (BSER). 25 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

25 This level of control has historically been referred to as best demonstrated technology (BDT).**02/2 8** **/2012 Draft**

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Page **43** of **233** elect whatever combination of measures will achieve equ ivalent or greater control of emissions. When the EPA establishes standards of performance for new sources of a pollutant that, in general, is not regulated under the CAA section 109 requirements for NAAQS or regulated under the CAA section 112 requirement s for HAPs, then, under CAA section 111(d)(1), the EPA must issue guidelines for states to regulate existing sources in the source category for that pollutant. The EPA intends to propose those guidelines in a separate rulemaking at a later date. Section 11 1(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 states 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 establish binding requirements that states 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**02/2 8** **/2012 Draft**

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Page **44** of **233** event that a state does not adopt and submit a plan, or submits a plan that the EPA disapproves, the EPA is then obligated to issue a federal plan. 40 CFR 60.2 7(c). B. Overview of Climate Change Impacts from GHG Emissions In 2009, the EPA Administrator issued the 2009 Endangerment Finding, 26 under CAA section 202(a)(1), as part of the process for promulgating the Light Duty Vehicle Rule. 27 With the Endangerment Fi nding, the Administrator found that elevated concentrations of GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare. These adverse effects on public health and welfare are summarized here, and described in more detail in the RIA. As explained in the Endangerment Finding, the EPA made this determination based primarily upon the recent, major assessments by the U.S. Global Change Research Program (USGCRP), Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC). 28 In brief, these assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their

26 "Endangermen t and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act." 74 FR 66496 (December 15, 2009). 27 "Light - Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule." 75 FR 25 324 (May 7, 2010). 28 74 FR 66510 - 66511.**02/2 8** **/2012 Draft**

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Page **45** of **233** coverage of the GHG and climate change problem, and underwent rigorous and exacting peer review by the e xpert 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. 1. Public Health Impacts Detailed in the 2009 Endangerment Finding Climate 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 vuln erable to these climate related health effects. By increasing higher average temperatures, climate change increases 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 suggests 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.**02/2 8** **/2012 Draft**

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Page **46** of **233** Public health t hreats 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 ther e is the potential for hurricanes to become more intense, and 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 men tal health problems such as post - traumatic 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 Cli mate change is expected to have numerous effects on public welfare. Large 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 f ace 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**02/2 8** **/2012 Draft**

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Page **47** of **233** 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. 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 oz one, changes in the intensity and frequency 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 incr easing 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 - re aching 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 f uture emissions but indeed by present - 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**02/2 8** **/2012 Draft**

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Page **48** of **233** 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 Since the 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 the EPA based the Endangerment Finding. In May 2010, the NRC, which is the operating arm 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). 29 It concluded that “climate c hange 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.” 30 Furthermore, the NRC stated that this conclusion is based on findings that are “consistent with the conclusions of recent assessments by the U.S. Global Change Research Program, the Intergovernmental Panel on Climate Change’s

29 NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. 30 NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. Page 3.**02/2 8** **/2012 Draft**

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Page **49** of **233** Fourth Assessment Report, and other assessments of the state of scientific knowledge on climate change.” 31 These are the same assessments that served as the primary scientific references underlying the 2009 Endangerment Finding. The 2010 NRC Assessment also warned of risks associated with abrupt changes and surprises that might occur when certain thresholds a re 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 acid ification. 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 for many centuries. The report also estimates a number of specific climate change impacts, finding that every degree Celsius (oC) of warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic sea ice e xtent, along with other precipitation and stream flow changes. The assessment also found that with an increase of 4 oC, the average summer would be as warm as the warmest summers of the past

31 NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. Page 286.**02/2 8** **/2012 Draft**

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Page **50** of **233** century, that for an increase of 1 to 2 oC the area burnt by wild fires in western North America 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 oC scenario. The assessment notes that many important aspects of climate change are difficult to quantify but that the risk 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 recent 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 elect ric utility generating units 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**02/2 8** **/2012 Draft**

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Page **51** of **233** Emissions and Sinks 32 (the U.S. GHG Inventory) to comply with existing commitments under the United Nations Framework Convention on Climate Change. This inventory, which includes recent t rends, 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 2009. **Table 2. U.S. GHG Emissions and Sinks by Sector (teragram carbon dioxide equivalent (Tg CO**  **2 Eq.))**  **33 SECTOR**  **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 Use, 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

32 “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. 33 From Table 2 - 3 of the EPA GHG Emissions and Sinks Inventory, EPA 430 - R - 11 - 005.**02/2 8** **/2012 Draft**

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Page **52** of **233** Energy - related CO 2 emissions are the largest contributor to total U.S. GHG emissions, 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

– - account ed 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, natural gas and petroleum systems, and incineration of waste. Direct fuel use in the residential and commercial sectors accounted for 26 percent of total CO 2 emissions in 200 9. Total CO 2 emissions from fossil - fuel - fired EGUs, for years 1990, 2000 and 2009, are shown below in Table 3. **Table 3. U.S. GHG Emissions from Generation of Electricity from**

**Combustion of Fossil Fuels (Tg CO 2**  **Eq.) GHG EMISSIONS**  **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**02/2 8** **/2012 Draft**

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Page **53** of **233** 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 NO X control. We are not proposing separate N 2 O or CH 4 emis sion 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 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 el ectric 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 Total N 2 O - stationary combustion 8.1 10.0 9.0**02/2 8** **/2012 Draft**

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Page **54** of **233** category. ”Standards of Performance for Electric Utility St eam 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. Court of Appeals for the District of Columbia Circuit (the Court), contending, among other things , that the rule was required to include s tandards of performance for GHG emissions from EGUs. The two groups of petitioners were (1) the States of New York, California, Connecticut, Delaware, Maine, New Mexico, Oregon, Rhode Island, Vermont, and Washington, the Commonwealth 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 portions of State and Environme ntal 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 York, et al. v. EPA, No. 06

– 132 2. Following the U.S. Supreme Court’s**02/2 8** **/2012 Draft**

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Page **55** of **233** 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 Massachusetts. 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 incl udes 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 pa rt 60, subpart Da if they were new sources. Pursuant to CAA section 113(g), the EPA published notice of the proposed settlement agreement in the Federal Register, and provided for a public comment period. 75 FR 82392 (December 30, 2010). 34 The EPA considere d 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

34 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.**02/2 8** **/2012 Draft**

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Page **56** of **233** Electric 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 eff orts achieve their intended environmental objectives in a common sense manner. The confluence of these rulemakings allows the industry to look across the regulatory requirements and design cost effective integrated compliance strategies . 35 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
r educing power plant emissions that contribute to ozone and fine particle pollution in other states. On July 6, 2011, the EPA also issued a supplemental proposal that requires six states to make summertime NO X reductions under CSAPR’s ozone - season control p rogram. 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 an nual NO X reductions, and May 1, 2012 for ozone season NO X reductions. By 2014,

35 We include this discussion of other rulemakings for background purposes. The effort to coordinate rulemakings does not provide a defense to a violation to the CAA. Sources cannot defer compliance with existing requirements because of othe r upcoming regulations.**02/2 8** **/2012 Draft**

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Page **57** of **233** combined with other final state and EPA actions, the CSAPR will reduce power plant SO 2 emissions by 73 percent and NO X emissions by 54 percent from 2005 levels in the CSAPR regi on. 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 finalize later this year, will re quire 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, the EPA proposed to revise the NSPS for criteria 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 NO X , can also reduce or help to reduce HAP emissions, coordinating compliance strategies for the CSAPR and MATS rules, including the revised NSPS for criteria pollutants, will allow cost - effective compliance options. In April, 2011, the EPA proposed standards under the Clean Water Act (CWA) to reduce injury and death of fish and other aquatic life caused by cooling water intake str uctures 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**02/2 8** **/2012 Draft**

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Page **58** of **233** standards, the EPA’s commo n sense proposal would greatly reduce damage to ecosystems while accommodating site - specific circumstances and providing cost effective options. The EPA recognizes that it is important that each of these efforts achieves its intended environmental objectiv es in a common 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, simplification, and harmonization. Each agency shall also seek to iden tify, as appropriate, means to achieve 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 constraints permit, in ways that allow the industry to mak e practical investment decisions that minimize costs in complying with all of the final rules, while still achieving the fundamentally important environmental and public health benefits that the rulemakings must achieve. F . PSD and Title V Implications Commenters have asked whether the rulemaking the EPA is**02/2 8** **/2012 Draft**

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Page **59** of **233** 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 i n that discussion. G . 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 organiza tions, and many regional, State, and local air quality management agencies that have been actively engaged in efforts to address GHG emissions over a period of several years. In addition to these conversations, as part of developing this proposed rule, the EPA held five listening sessions in February and March 2011 to obtain additional information and input from key stakeholders and the public. Each of the five sessions had a particular target audience: the electric power industry, environmental and environmental justice organizations, states and Tribes, coalition groups, and the petroleum refinery industry. Each session lasted two hours and featured a facilitated round table discussion among stakeholder representatives who were identified and selected for t heir expertise in the CAA standard setting process. The EPA had asked key stakeholder groups to identify**02/2 8** **/2012 Draft**

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Page **60** of **233** these round table participants. The EPA accepted comments from the public at the end of each session and via the electronic docket system. From the lis tening 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, included the following:

 Feasibility and availabi lity of control technologies

 Output - based standards

 Subcategorization factors

 Fleet - wide averaging

 Neutrality of fuels

 Role of efficiency improvements

 Equivalency of state and regional reduction programs

 Recognition of early action by industries and sta tes achieving reductions

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

 Market - based flexibility

 Use of a tiered structure, with requirements evolving over time

 Credit for replacement of older, less efficient generation units

 Role of biomass**02/2 8** **/2012 Draft**

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Page **61** of **233**  Consideratio n of compliance issues arising from conflicts with other regulatory programs

 Schedule for proposing and promulgating this rule

 Small business impacts Comments 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 Sources** This section describes the proposed requirements in this rulemaking for new sources. Our rationale for these proposed requirements is provide d 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 considered both covered EGUs as defined by this 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 an d more than 25 MW net - electrical output to any utility power distribution system for sale, with certain exceptions**02/2 8** **/2012 Draft**

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Page **62** of **233** noted below. For this proposed rule, covered EGUs include electric utility steam generating units (“boilers”), combined cycle combustion turb ines and their associated heat recovery steam generators (HRSG) and duct burners; and IGCC units, including their combustion turbines and associated 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 Emissions Only This action proposes to regulate covered EGU emissions of CO 2 , and not other constituent gases of th e air pollutant GHG, although we identify the pollutant we propose to regulate as GHGs. Note that emissions of criteria pollutants for covered EGUs remain covered under 40 CFR part 60 subparts Da and KKKK. 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 s uch 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**02/2 8** **/2012 Draft**

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Page **63** of **233** according to its terms for purposes of this rulemaking, except that special considerat ions 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 (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. 36 Specifically, the EPA is proposing a standard of 1,000 lb CO 2 /MWh, but, as discussed below, is

36 As discussed below, we are not proposing such a limit for modifications, transitional sources, or reconstructed sources.**02/2 8** **/2012 Draft**

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Page **64** of **233** 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 rolling 12 - month period . In the alternative, we solicit comment on requiring calculation of compliance on an annual (calendar year) period. Under this proposal, no averaging or emissions trading among affected sources would 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 . Alternativ e compliance option We also propose an alternative compliance option that would be available only for affected sources that comply with the standard through the use of CCS. This approach involves a performance standard that includes both a 12 - month rolling average limit and a longer - term limit that may be met on an average basis by the end of a 30 - year period. The 12 - month limit is important because it is a practicably enforceable mechanism to ensure that the so urce is on a path to comply with the 30 - year average limit. The annual limit will ensure that the source takes timely action to meet a 30 year limit. For**02/2 8** **/2012 Draft**

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Page **65** of **233** instance, if meeting the 30 year limit was predicated on installing CS technology before year eleven of operation, the annual compliance limits would provide an enforceable measure to ensure that CCS was installed and operating well before a 30 year average could be calculated. Specifically, for the first ten years of operation, the affected sources woul d be required to comply with 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). This proposed emission limit can be met by modern coal - fired facilities using supercritical steam conditions, IGCC facilities, and p ressurized circulating fluidized bed boilers. By no later than the 11 th year from the effective date of the rule, the facility would be required to meet a reduc ed emission limit of no more than 600 lb CO 2 /MWh (272 kg CO 2 /MWh) (gross) on a 12
- month rolling average basis for the remaining20 years of the 30 - year averaging period , 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 performance of 1,000 lb CO 2 /MWh. This reduced**02/2 8** **/2012 Draft**

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Page **66** of **233** emissions standard during the remainder of the 30 - year period would be met with some level of CCS . 37 For added flexibility, under this option, we are taking comment on allowing the owner/operator to select a different two
- step trajectory to achieving the 30 year average as long as the owner/operator obtains EPA approval of that rate before beginning op erations. Such a trajectory would have to assure that assuming similar amounts of operation in each year that the overall overage emission rate would be at or below the required 30 year average of 1000 lbs/CO 2 per MWh. For instance, if an owner or operator wished to operate at a rate of 2000 lbs/MWh for the first period, they would have to commit to something more stringent than achieving a 600 lbs/MWh standard by the 11 th year. Potential compliance pathways could include committing to a limit of 500 lbs CO 2 /MWh by the 11 th year or committing to a limit of 600 lbs CO 2 /MWh by the 8 th year. The EPA is also soliciting comment on what additional requirements would be necessary to implement the 30 - year averaging requirement. Specifically, if the owners or operat ors did not intend

37 As discussed elsewhere, EPA is soliciting comment on whether the emissions standard that reflects CCS should be somewhat higher or lower than 1,000 lb CO 2 /MWh, and whether the emissions standard that reflects supercritical efficiency should be somewhat hi gher or lower than 1,800 lb CO 2 /MWh. If EPA does promulgate a higher or lower standard in either case, then EPA may revise the 600 lb CO 2 /MWh amount accordingly.**02/2 8** **/2012 Draft**

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Page **67** of **233** to install CCS when the unit commenced operation, they could 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 ke y milestone dates such as soliciting proposals, obtaining financing, beginning construction, 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 th e facility have adequate plans in place to meet the 30 - year average emission rate requirement. Further, the shorter term emission limits for the entire 30 - year period must be included in the source’s title V permit. In addition, the EPA solicits comment on requiring compliance through an annual (calendar year) average emission limit as an alternative to a 12 - month rolling average. W e solicit comment on the enforceability of the 30 - year averaging period, how we can ensure that the owner/operator will comply with the second phase of the standard and what sort of compliance demonstrations are appropriate with such a long - term standard. We also solicit comment on whether this alternative compliance mechanism should automatically terminate in 2020 such that only facilities that commenced construction prior to 2020 would be able to use the 30 - year average. The EPA suggests that this alternative compliance option may be**02/2 8** **/2012 Draft**

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Page **68** of **233** warranted for at least t wo reasons. First, it provides 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 . 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 over the next decade from a dozen DOE - funded demons tration projects. 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. A second reason that this alterna tive may be practicable is, that even for sources installing and operating CCS at the beginning of a project, there may be startup issues (other than related to the capture technology or the arrangements for sequestr at ion). For instance, a company’s abilit y to sequester may be dependent upon construction by a third party of a pipeline that will be transporting the CO 2 to a site to be used for enhanced oil recovery or permanent sequestration. Because the owner or operator does not have direct control over th is part of the project, there may be concerns that it will not be completed on time and that even after spending all of the money to construct a coal -**02/2 8** **/2012 Draft**

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Page **69** of **233** fired unit capable of capture, it will have to remain non - operational for a period of time until the pipel ine project or sequestration destination is completed. The alternative compliance option could provide flexibility to operate the unit until the pipeline was completed as long as the carbon capture system is designed to meet a rate sufficiently below 1000 lbs CO 2 /MWh to allow for compliance with a 30 - year averaging period. Such flexibility is likely to be most important for the first several CCS projects (i.e., “first movers”) because both the complexity of integration of the technologies and the business model is new for the power sector. Because the policy purpose of this alternative compliance option is to leave open the option of building a coal - fired unit in the near term and installing CCS after several years or to allow for flexibility during startup of the system, a long - term 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, re vise [the] standards [of performance] ... ”. This review is required to take place in 2020, if not sooner. In the event that the EPA adopts the alternative 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**02/2 8** **/2012 Draft**

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Page **70** of **233** whether or not the 30 - year averaging approach is still warranted for new sources. Because we expect CCS technology to advance significantly 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 automati cally terminate in 2020, so that it would be available only for facilities that commenced construction prior to 2020. We recognize that this compliance option, by authorizing sources to average the emission level over a 30 - year period, is unique. We recognize that the uniqueness of this approach may give rise to new issues concerning compliance and enforcement. We solicit comment on any practical difficulties in compliance and enforcement. Along these lines, although we propose that sources be required to retain records to demonstrate compliance with the emission limits for at least 30 years following the date of initial s tartup of the affected EGU, we solicit comment on the merits of extending this period to 50 years. As with the proposed standard of performance, no averaging or emissions trading among affected sources would be allowed for this alternative compliance optio n. We seek comment on all aspects of this alternative compliance option.**02/2 8** **/2012 Draft**

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Page **71** of **233** C. What are the startup, shutdown, and malfunction requirements? 1 . Startups and S hutdowns The NSPS that the 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. The EPA is not proposing different 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 mo re accurately reflects overall environmental performance. In addition, because low - load hours do not factor as heavily into the calculated average, the impact of including periods of startup and shutdown is minimized when calculating emission rates. We so licit 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.**02/2 8** **/2012 Draft**

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Page **72** of **233** 2 . Malfunctions T he NSPS that the EPA is proposing in this action would apply at all times, including during 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 requires that the EPA anticipate and account for the innumerable types of potential malfu nction 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 anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by ‘uncontrollable act s of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case - by - case enforcement discretion, not for specification in advance by regulation .”)**02/2 8** **/2012 Draft**

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Page **73** of **233** Further, it is reasonable to interpret CAA section 111 as not requiring the EPA to account for malfunctions in setting emissions standards. For example, we note that section 111 provides that the EPA set standards of performance which reflect the degre e 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 dur ing which a source is malfunctioning presents difficulties. The ‘‘application of the best system of emission reduction’’ is more appropriately understood to include operating units in such a way as to avoid malfunctions. Further, accounting for malfunction s would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of vario us malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable. See, e.g., Sierra Club v EPA , 167 F.3d 658, 662 (D.C. Cir. 1999) (The EPA typically has wide latitude in determining the extent of data - gathering necessary to solve a problem. We generally defer to an agency's decision to proceed on the basis of imperfect scientific information, rather than to "invest the resources to**02/2 8** **/2012 Draft**

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Page **74** of **233** conduct the perfect study."). In addition, the goal of a best cont rolled 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 - malfunc tioning 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 111 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 emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertai n and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 111 standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or c areless operation.” 40 CFR section 60.2 (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 emissi on standard. ( See, e.g., “State Implementation Plans: Policy Regarding Excessive**02/2 8** **/2012 Draft**

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Page **75** of **233** Emissions During Malfunctions, Startup, and Shutdown” (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983), whi ch 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 60.10042 (defining “af firmative defense” to mean, in the context of an enforcement 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 judi cial or administrative proceeding.) . We also are proposing other regulatory provisions to specify the elements that are necessary to establish this affirmative defense: the source must prove by a preponderance of the evidence that it has met all of the el ements set forth in 60.10001. (See 40 CFR 22.24). The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 60.2 (sudden, infreque nt, not reasonably preventable and not caused by poor maintenance and or careless operation). For example, to successfully assert the affirmative defense, the source must prove by a preponderance of the evidence that excess emissions “[w]ere caused by**02/2 8** **/2012 Draft**

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Page **76** of **233** a su dden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to 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 60.10001 and to prevent future malfunctions. For example, the source must prove by a preponderance of the evidence that “[r]epairs were made as expeditiously as possible when the applicable emission limitat ions 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 th e 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) . The EPA is includ ing an affirmative defense 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 “limit the quantity, rate, or**02/2 8** **/2012 Draft**

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Page **77** of **233** concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. §7602(k)(defin ing “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 even ts meets this requirement by ensuring that even where there is a malfunction, the emission limitation is still enforceable through injunctive relief . 38 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. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that in setting standards under CAA sectio n 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 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.

38 Note that the Ninth Circuit recently upheld EPA’s decision to apply this affirmative defense approach to only actions seeking civil penalties, and not also to actions seeking injunctive relief. Montana Sulfur & Chemical Co. v. EPA, No. 02 - 71657 (9th Cir. August 31, 2011) (slip op. at 456).**02/2 8** **/2012 Draft**

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Page **78** of **233** 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 exce ss 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 Ninth Circuit required this type of formalized approach whe n 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). Th e 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 thus support the reasonableness of the standard as a whole. We propose that these same requirements for malfunctions would apply to the 30 - year averaging portion of the alternative compliance option ; however, we take comment on whether it is appropriate to have an affirmative defense for the 30 - year averaging porti on of the alternative compliance option, given that we would expect malfunctions to only impact shorter emissions limits, and the longer**02/2 8** **/2012 Draft**

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Page **79** of **233** the compliance period, the less likely malfunction events are to impact a source’s ability to meet the standard . D. Wha t are the continuous monitoring requirements? The EPA is proposing that a CO 2 mass rate CEMS and the associated automatic data acquisition and handling system must be installed and operated 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. 2 . Use all the data collected during all o ther required data collection periods in assessing the operation of the control device and associated control system. 3 . Report any periods for which the monitoring system failed to collect required data. 4 . Except for periods of monitoring system malfu nctions, 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 requir ed data is a deviation of the monitoring requirements.**02/2 8** **/2012 Draft**

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Page **80** of **233** 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). 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 requireme nts 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 certification requirements (40 CFR part 75.4(b)), we propose that owners/operators of a new unit, conduct an initial perfo rmance 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 a verage 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 beginn ing**02/2 8** **/2012 Draft**

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Page **81** of **233** on the first day of the first month following completion of the CEMS installation and certification. For all of the operating hours during each monthly period, including startup and shutdown, you would calculate compliance with the emissions limit by d ividing 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 propose that these same emissions performance testing requirements would apply to the 30 - year alternative compliance
o ption. F. What are the continuous compliance requirements? In this rulemaking, we propose 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 limi t 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 calendar 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**02/2 8** **/2012 Draft**

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Page **82** of **233** requirements in the section 111 regulatory general provisions. 40 CFR part 60, subpart A. We solicit comment on, in the alternative, an annual (calendar year) avera ge 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, recordkeepi ng, 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 identi fied 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 , NO x , CO 2 , and other related data. We propose for affected sources to**02/2 8** **/2012 Draft**

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Page **83** of **233** 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. 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 modificati on of the ECMPS system to collect, track, and calculate CO 2 emissions rates based on hourly useful energy output for the unit. We also request comment on tracking and making use of useful steam data for new facilities. We are also aware that owners or oper ators of existing units are required to submit electrical generation data according to procedures required by the DOE’s Energy Information Administration (EIA) for its reports. We request comment on the appropriateness of using these electrical generation data in this proposed rule. The EPA proposes that these same notice, recordkeeping, and reporting requirements would apply to the 30 - year averaging portion of the alternative compliance option. The EPA requests comment on whether any alterations or additions are appropriate for the notice, recordkeeping, and reporting requirements that would apply to the alternative compliance option . The EPA also requests comment on**02/2 8** **/2012 Draft**

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Page **84** of **233** whether sources that utilize the alterna tive compliance option should include , as applicable requirements in their title V permits, a specific explanation of 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. **IV. Rationale for the Propose d Standards for New Sources**  A. How did the EPA establish the emission limits? 1. Rationale for Combining the Subpart Da Category and a Component of the Subpart KKKK Category into a New Category for GHGs The EPA is proposing to create a new subpart in 40 CF R part 60 by combining the sources in subpart Da (the Da category) and components of sources in subpart KKKK (the KKKK category)

–– combined cycle units, but not simple cycle units -- for purposes of promulgating standards of performance for emissions of G HGs 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 components of the KKKK category for conventional pollutants. CAA section 111 provides legal authority for combining the categories into a new category. Clean Air Act section 111(b)(1)(A) provides:**02/2 8** **/2012 Draft**

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Page **85** of **233** The Administrator shall, within 90 days after December 31, 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. (Emphas is 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 catego ries 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 o f 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 of their design or fuel type. Second, although it is true that natural gas - fired plants are inherently less emitting than coal - fired plants,**02/2 8** **/2012 Draft**

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Page **86** of **233** all newly constructed sources have options in selecting their design. As a result, prospective owners and operators of new sources could comply with the proposed emiss ion standards by choosing to construct a NGCC facility. These two factors provide sufficient legal rationale for the EPA to combine the Da category and the combined cycle component of the KKKK category for purposes of GHGs. A third factor lends further support. Combining the categories does not raise adverse policy concerns. Based on comments made during the listening sessions, we anticipate that some commenters may express concern that combining the categories and applying the NGCC standard may limit c onstruction of new coal - fired power plants, which would have adverse implications for energy diversity. We do not believe that this action would have those effects. As discussed below, modeling of the power sector, which is based on economic factors, forec asts no new coal - fired construction through the modeling period, which lasts until 2020. Accordingly, economic conditions may be expected to be the main driver precluding, or at least limiting, construction of coal - fired EGUs. Even so, we recognize the pos sibility that a limited amount of new coal - fired construction may nevertheless occur. Today’s action would not foreclose construction of new coal - fired EGUs . Rather , the small number of new coal - fired EGUs th at may be expected to be built in the**02/2 8** **/2012 Draft**

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Page **87** of **233** 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 both feasible and sufficiently available, although not the least - cost choice, as evidenced by the fact that power companies have announced plans to incorporate CCS at seven already permitted coal - fired EGU construct ion projects in this country (as we discuss below in section V.B., concerning transitional sources). Programs exist that provide some funding for CCS through pilot or other demonstration programs , and we expect those to co ntinue. In addition, we reasonably expect the costs of CCS to decline over time. As discussed below , we are not proposing that CCS does or does not qualify as the “best system of emission reduction” that “has been adequately demonstrated .” Rather, the feasibility of CCS and its availability for the limited amount of new coal - fired construction that may be expected, means that this action to combine the categories and establish the NSPS at the proposed emissions l imit will not have adverse effects on new coal fired construction or, therefore, on energy diversity. In fact, this action could promote coal - fired construction by eliminating the current uncertainty about the prospect of GHG controls. On the other hand, at this time, we do not consider it**02/2 8** **/2012 Draft**

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Page **88** of **233** 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 pla nt is different than that of a new combined cycle plant or coal - fired plant. Combined cycle plants and coal - fired plants are typically designed to provide base - load or intermediate load power, while simple cycle turbines are designed to provide peaking pow er. Because combined cycle power plants and coal - 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 this source category. By the same token, at this time, we do not co nsider 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 c onventional pollutants to choose from, those controls generally do not reduce their conventional emissions to the level of conventional emissions**02/2 8** **/2012 Draft**

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Page **89** of **233** from natural gas - fired EGUs. 2. Endangerment and Cause - or - Contribute - Significantly Finding a. Overview. In today’s rulemaking, we propose or solicit comment on al ternative 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 section 111 provides that once the EPA lists a source category fo r 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 requirements 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 antic ipated 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 specifically covered by the endangerment finding the EPA made when l isting the source 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)),**02/2 8** **/2012 Draft**

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Page **90** of **233** 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 pl ants 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 not to require a specific endangerment finding or cause or contribute finding, but s imply to require the EPA to establish a rational basis for regulating an air pollutant from a source category. In this case, the 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, as an alternative for the basis for a
r ational 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 Prerequisite to Regulation. In this rulemaking, the EPA proposes to interpret CAA section 111 so that we are not required, as a 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**02/2 8** **/2012 Draft**

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Page **91** of **233** finding as to the extent that affected sources contribute to that air pollution. Clean Air Act section 111(b)(1)(A), by its terms, requires that the Administrator list a source category for regulation if the “category ...in [the Administrator’s] judgment, ... cause s or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.” Clean Air Act section 111(b)(1)(B) goes on to provide that after listing the source category, the EPA must promulgate regulations “es tablishing 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 (taki ng 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 si gnificantly to air pollution that endangers public health or welfare, and then to promulgate standards of performance for particular pollutants, section 111 does not by its terms require that the EPA make any endangerment finding with respect to those part icular pollutants, or any cause - or - contribute - significantly finding with respect to the**02/2 8** **/2012 Draft**

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Page **92** of **233** source category, at the time the EPA promulgates the standards of performance for those pollutants. The lack of any such requirement contrasts with (i) the definition of “standard of performance,” which specifically requires 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 regul ate particular pollutants from that source category, CAA section 111 does not require that the EPA make an endangerment finding for the relevant air pollution or a cause - or - contribute - significantly finding for the relevant air pollutants from that source c ategory . 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 categorie s only after determining that the source category “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” The EPA has previously determined that each of the Da and**02/2 8** **/2012 Draft**

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Page **93** of **233** KKKK categories c auses or contributes 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 be cause the EPA has already found that at least one component of the new category - – the former Da sources -- by itself causes or contributes significantly to such air pollution. There is no reason why this expansion of the Da category to include the pre - exi sting 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 o r 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 Interpretation: 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 endangerment finding specifically for the rel evant air pollution and
a cause - or - contribute - significantly finding specifically for the**02/2 8** **/2012 Draft**

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Page **94** of **233** relevant source category and air pollutant. In particular, what 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 the EPA did not make those findings under CAA section 111, it is the EPA’s view that the EPA would satisfy the need 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 lis ted 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 pollution 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 en dangerment finding may be resolved through a petition to reconsider that finding under the applicable CAA provision.**02/2 8** **/2012 Draft**

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Page **95** of **233** Applying this alternative interpretation 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 anticip ated to endanger public health or welfare in order for the 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 p romulgating 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 r egulating such emissions under CAA section 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 fired EGUs emit almost one - third of all U.S. GHG emissions, and constitute by far the largest single stationary source category of**02/2 8** **/2012 Draft**

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Page **96** of **233** GHG emissions. Indeed, so great is the contribution of CO 2 air pollutants from EGUs to GHG air pollution, that it is simply n ot 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 fa ct that GHG air pollution is caused by a large number of types of sources and that no one source category dominates the entire inventory. d. Second alternative interpretation: Rational Basis Prerequisite. As a second alternative interpretation, the lack of any requirement in CAA section 111 addressing 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 st ep 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 emission s of the particular pollutants. That rational basis may consist of some type of factual showing that is consistent with the purposes of CAA section 111, but may be something short of an endangerment and a cause - or - contribute - significantly finding .**02/2 8** **/2012 Draft**

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Page **97** of **233** 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 a ir pollution may reasonably be anticipated 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 a ction that entailed further review of scientific 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 t hese options, the EPA would need to establish 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 emissions, as discussed above, would readily provide such a rational basis.**02/2 8** **/2012 Draft**

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Page **98** of **233** 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 plants will be constructed in the foreseeable future. Although a small number of new coal - fired power plants have been built recently, the industry generally is not building these kinds of power plants at present and is not expected to do so for the time being. The reasons include the current economic environment, which has lead to lower electricity demand; and competitive natural gas prices. Natural gas prices have stabilized over the past few years as new drilling techn iques 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. On average , the cost of generation from a new NGCC power plant is expected to be lower than the cost of generation from a new coal - fired power plant. 39 Other drivers that may influence decisions to build new power plants are State and Federal energy and tax policies. Many states have adopted renewable portfolio standards (RPS), which require that

39 Levelized Cost of New Generation in the Annual Energy Outlook 2011 http://205.254.135.24/oiaf/aeo/electricity_generation.html .**02/2 8** **/2012 Draft**

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Page **99** of **233** a certain portion of electricity 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 power 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 proje ctions 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 pow er plants that are currently under construction and expected to begin operation in the next year or two. According to the AEO 2011, the majority of new generating capacity will be either natural gas - fired or renewable, with some lesser amounts of nuclear p ower. The AEO 2011 is based on existing policy and regulations, such as state RPS programs and Federal tax credits for renewables. 40 The new generation that EIA does show coming on - line after 2012 fits into one of three categories . It

40 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm .**02/2 8** **/2012 Draft**

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Page **1 00**  of **233** is generation th at is currently under construction, generation that will include CCS or industrial CHP . Units in the first group would not be subject to 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 action . Units in the third group would not be subject to this rule because CHP units that generate primarily on - site powe r are not considered EGUs and are thus not affected by the rule . The EPA modeling using the Integrated Planning Model (IPM), a detailed 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. 41 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 lim ited 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) allowing 30 - year averaging as a alternative compliance option for

41 http://www.epa.gov/airmarkets/progsregs/epa
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Page **101** of **233** coal - fir ed power plants because CCS is feasible and sufficiently available for the few such plants expected, in light of the demonstration programs or other incentives available for CCS , couple d with the prospects that the costs of CCS will decline over time . 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 (430 to 500 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 Standard. For reasons explained below (see “d. Legal Justification for the Standard 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 reviewed the emissions rate of natural gas - fired non combined heat and power combined cycle facilities used in the power sector that commenced operation between 2006 to 2010 that that report complete generation data to EPA. Based on this analysis, nearly 95% of these facilities meet the proposed standards on an annual basis. These units represent a wide range of geographic locations (with differing elevations and ambient temperatures), operational cha racteristics, and sizes .**02/2 8** **/2012 Draft**

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Page **102** of **233** We are requesting comment on a range of 950 to 1,100 lb/MWh (430 to 500 kg/MWh) for the final rule. The upper limit would incorporate essentially all available new combined cycle designs and would hav e 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 could limit presently available options for generation below approximately 40 MW. However, an owner/operator of combined cycle facilities with higher heat rates could eithe r implement combined heat and power (CHP) or integrated solar thermal for feedwater heating to achieve the proposed standard. (2) States Implementing a Comparable Standard. Several states 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, in September 2006, California Governor Schwarzenegger signed into law Senate Bill 1368. The law limits long - term investments in baseload g eneration 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**02/2 8** **/2012 Draft**

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Page **103** of **233** designed regulations that estab lish 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 signed Substitute Senate Bill 6001, which established statewide GHG emissions reductio n 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 state. Baseload generation fa cilities must initially comply with an emission limit of 1,100 lb CO 2 /MWh. In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that facilities generating baseload electricity, whether gas - or coal - fired, must have emissions equ al 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 distillate - 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 Compliance Alternative. In this section, we describe the basis for our position that CCS is a compliance alternative for coal - fired power plants because CCS is feasible and**02/2 8** **/2012 Draft**

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Page **104** of **233** sufficiently available in light of the limited amount of new coal fired construction expected. In brief, first , 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 high , we have reason to expect that the costs of CCS will decrease over time . This action will itself contribute to downward pressure on CCS costs by shifting the regulatory landscape towards CCS, consistent with t he recent report by Interagency Task Force on Carbon Capture and Storage, established by President Obama on February 3, 2010, which we describe below. Third, we expect construction of no more than a few new coal - fired power plants by 2020, and t hose may well be able to take advantage of demonstration programs or other sources 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 plan ning stages. (1) Technological Feasibility of CCS. The current state 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**02/2 8** **/2012 Draft**

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Page **105** of **233** widespread, cost - effective deployment of CCS within 10 years, with a goal of bringing fi ve to ten commercial demonstration projects online by 2016. The Task Force found that, although early CCS projects face economic challenges related to climate policy uncertainty, first - of a - kind technology risks, and the current high cost of CCS relative t o other technologies, there are no insurmountable technological, legal, institutional, 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 over all 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 widespread 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**02/2 8** **/2012 Draft**

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Page **106** of **233** power generation can be categorized into three approaches 43 :
 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.

 Oxy - combustion uses high - purity O 2 , rather than air , to combust coal and therefore produces a highly concentrated CO 2 stream. Each of these three carbon capture approaches (pre - combustion, post combustion, and oxy - combustion) is technologically feasible. However, each results in increased capital and oper ating 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 Availabi lity of Transportation and Sequestration. 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. Carbon diox ide has been transported via pipelines 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
43 IPCC, 2005; DOE, 2007.**02/2 8** **/2012 Draft**

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Page **107** of **233** review of the 500 largest CO 2 point sources in the U.S. shows that 9 5 percent are within 50 miles of a possible geologic sequestration site, 44 which would lower transportation costs. For all these reasons, the transportation component of CCS is not expected to be a significant stumbling block to the commercial availability of CCS. With respect to sequestration, globally, 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 sequestere d. 45 These four sites represent over 25 years of cumulative experience on safely and effectively storing anthropogenic CO 2 in appropriate deep geologic formations. 46 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

44 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 Technol ogy Strategy to Address Climate Change. Joint Global Change Research Institute, Battelle Pacific Northwest Division. PNWD - 3602. College Park, MD. 45 These projects are: Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah in Algeria, and Weyburn in Canada. 46 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.**02/2 8** **/2012 Draft**

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Page **108** of **233** formations, oil and gas reservoirs and unmineable coal seams. 47 The U.S. experience with large - scale CO 2 injection, such as at enhanced oil and gas recovery projects, 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. It should be noted that the EPA rec ently 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 Sa fe 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. 48 The UIC Class VI regulat ions 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

47 U.S. Department of Energy National Energy Technology Laboratory (2010). Carbon Sequestration Atlas of the United States and Canada, Third Edition. 48 Federal Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells, Final Rule, 75 FR 77230 (Dec. 10, 2010).**02/2 8** **/2012 Draft**

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Page **109** of **233** monitori ng, 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
ca n 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 requirements, provides requirements for quantifyin g the amount of CO 2 sequestered by these facilities. 49 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. 50 That proposed rule is based upon the EPA's con clusion 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

49 Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide, Final Rule, 75 FR 75060 (Dec. 1, 2010). 50 Hazardous Waste Management System: Iden tification and Listing of Hazardous Waste: Carbon Dioxide (CO 2 ) Streams in Geologic Sequestration Activities, Proposed Rule, 76 FR 48073 (Aug. 8, 2011).**02/2 8** **/2012 Draft**

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Page **110** of **233** injection into permitted UIC Class VI wells. Together, these actions 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 that , at present, make CCS relatively costly . 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 focused on developing advanced technology options that dramatically lower the cost of capturing CO 2 from fossil - fuel energy plants compared to today’s available capture technologies. 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, a nd around 35 percent to the cost of electricity for a new advanced gasification 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**02/2 8** **/2012 Draft**

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Page **111** of **233** for new gasification - based power plants. 51 The large - scale CO 2 capture demonstrations that are currently planned and in some cases underway, under DOE’s initia tives, as well as other domestic and international projects, will generate operational knowledge and enable 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 and to produce food and chemical grade CO 2 . The advancement of amine - based solvents is an example of technology development that has improved the cost and performance of CO 2 capture. Most single component amine systems are not practical in a flue gas 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 less expensive, conventional materials of construction. Other commercially available processes use sterically hindered amine formulations (for example, the Mitsubishi Heavy Industries KS - 1 solvent) which are less susceptible to degradation and corrosion

51 DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap, U.S. Department of Energy National Energy T echnology Laboratory, December 2010.**02/2 8** **/2012 Draft**

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Page **112** of **233** 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 captur e 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 u sing a given technology declines as experience with that technology increases over time, 52 and this has certainly been the case with air pollution control technologies. Reductions in the cost of air pollution control technologies as a result of learning - by - doing, research and development investments, and other factors have been observed over the decades. We 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

52 These studies include John M. Dutton and Annie Thomas, "Treating Progress Functions as a Managerial Opportunity," 2, 235 - 247; Dennis Epple, Linda Argote, and Rukmini 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 Technology 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, 1985. See discussion in “The Benefits and Costs of the Clea n Air Act from 1990 to 2020,” U.S. EPA, Office of Air and Radiation, April 2011.**02/2 8** **/2012 Draft**

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Page **113** of **233** 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 pla nts. 53 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 power plants, the energy required for CO 2 capture, the CO 2 capture ratio (removal efficiency) and the power plant availability. The model predicted contin ued reductions in cost with increased implementation. 54 In addition, we note that the Administration’s CCS Task Force report recognized that CCS could become more widely available with

53 Rubin, E.S.; Yeh, S.; Antes, M.; Berkenpas, M.; Davison, J.; “Use of experience curves to estimate the future cost of power plants with CO2 capture”, Intl. J. of Greenhouse Gas Control, 1, 188 (2007). 54 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.**02/2 8** **/2012 Draft**

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Page **114** of **233** the advent of a regulatory framework that promoted CCS. Today’s action is an important component in developing that framework . (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 - f ired EGUs. We also expect continued opportunity for financial support for some CCS projects through a variety of potential mechanisms such as direct grants, tax incentives and/or regulatory programs (e.g. Clean Energy S tandards such as guaranteed electricity purchase price agreements) 55
. 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 established requirements for CCS, and a number of projects with CCS have been approved and/or are under construction . In May 2007, Montana Governor Schweitzer signed House Bill 25, adopting a CO 2 emissions performance standard for electric generating units in the state. House Bill 25 prohibits the state Public Utility Commission from approving new electric generating units primarily

55 See Center for Climate and Energy Solutions, “Financial Incentives for CCS” - http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=8380 .**02/2 8** **/2012 Draft**

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Page **115** of **233** fueled by coal unless a minimum of 50 percent of the CO 2 produced by the facility is captured and sequestered. On January 12, 2009, Illinois Governor Blagojevich signed Senate Bill 1987, the Clean Coal Portfolio Standard Law. The legislation establis hes 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 planned CO 2 capture systems, including, in some cases, part of the components for coal - based power plant appli cations. 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 plants is subsequently used in the food processing industry 56
.

56 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Captu re and Storage Technologies as of**02/2 8** **/2012 Draft**

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Page **116** of **233** 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. 57 A pre - combustion Rectisol® system is used for CO 2 capture at the Dakota Gasification Company’s synthetic 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 - mi le pipeline, and injected into the Weyburn oilfield in Saskatchewan, Canada. In September 2009, American Electric Power Co. (AEP) began a pilot - scale CCS demonstration at its Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a 1,300 MWe coal - fi red unit that was retrofitted with Alstom’s patented 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 valid ation project. The AEP Alstom project, the world’s first facility to both capture and store CO 2 from a coal - fired power plant, represents a successful scale - up of ten times the size of previous field pilots (e.g., at We Energies June 2009. U.S. DOE, Pacific Northwest National Laboratory, under Contract DE - AC05 - 76RL01830. 57 IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris.**02/2 8** **/2012 Draft**

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Page **117** of **233** Pleasant Prairie). The demo nstration achieved capture rates from 75 percent (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 duri ng 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 integrat ed 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 un certain status of U.S. climate policy and the continued 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 (Schwarze Pumpe) has been operating since September 2008. It is**02/2 8** **/2012 Draft**

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Page **118** of **233** 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 demonstration 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 ge ologic formation. Southern Company has begun construction 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 4 00 MW IGCC facility located near Odessa, TX will capture 90 percent of its CO 2 , which is approximately 3 million tonnes annually. The captured CO 2 will be used for EOR in the West Texas Permian Basin. (Additionally, the plant will produce urea and smaller quantities of commercial - grade sulfuric acid, argon, and inert slag, all of which will also be marketed.) Construction is expected to begin in 2012 .**02/2 8** **/2012 Draft**

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Page **119** of **233** 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 works and is cost effective.” 58 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] option of generation with carbon capture." 59 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.
d. Legal Justification for the Standard of Performance and Alternative Compliance Optio n. This section describes our legal justification for proposing that new affected facilities in the TTTT

58 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 . 59 IRP, March 2011.**02/2 8** **/2012 Draft**

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Page **120** of **233** category
– - which combines 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 i nitial CO 2 emission limit of 1,800 lb CO 2 /MWh (816 kg 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 S tandard of Pe r formance. 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 u nder CAA section 111(a)(1) as follows: Definitions. 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 o f 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 apply this definition, in effect, from the bottom up. That is, first, we determine the “best system of emission reduction which**02/2 8** **/2012 Draft**

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Page **121** of **23 3**  (taking into account * * * cost [and other factors]) the Administrator determines has been adequately demonstrated.” For EGUs, that i s a NGCC facility, for reasons discussed below. 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 deg ree of emission limitation. This standard is 1,000 lb of CO 2 /MWh. These 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
o f natural gas - fired and coal - fired generation 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 d eployed in Asia (especially China)

– - and it 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 l b/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.**02/2 8** **/2012 Draft**

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Page **122** of **233** 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 NGC C is a much more efficient, less expensive, and more widely used technology. We propose that a NGCC facility is the best system of emission 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 projects that for economic reasons, natural g as - fired EGUs will be the facilities of choice until at least 2020, 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 has come about primarily because technolog ical 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 - fir ed plants are the facilities of choice, the proposed standard of performance in today’s rulemaking

–– which is**02/2 8** **/2012 Draft**

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Page **123** of **233** 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 n onair 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 a ny nonair quality health and environmental impact and 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 category, and appl ying 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, notab ly 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 per formance 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**02/2 8** **/2012 Draft**

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Page **124** of **233** a mechanism for t he 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 Compliance Option. Although the IPM model projects that for economic reasons, new coa l fired EGUs will not be built in the foreseeable future, we recognize that in a few instances, owners or operators may in fact seek to build coal - fired EGUs. As discussed in detail below, those owners or operators could avail themselves of CCS as an alternative compliance option . In addition, today’s proposed rulemaking offers flexibility for CCS installation: The owners or operators could (i) achieve the supercritical efficiency level for an initial period (e.g., u p to the first 10 years), and (ii) after that, implement CCS so as to achieve a 600 lb CO 2 /MWh rate on a 12
- month rolling average during the latter period (i.e., the back 20 years) and thereby achieve the 1,000 lb CO 2 /MWh rate on an average annual basis over the 30 - year period. The alterantive compliance option could also allow them to install and operate CCS much earlier and use the 10 year period to address any startup challenges related to being an early adopter of the technology . Because CO 2 is long - lived in the atmosphere, the 30 - year averaging period , as structured, with shorter term compliance**02/2 8** **/2012 Draft**

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Page **125** of **233** requirements, is not expected to have a different impact on climate compared to meeting the standard of performance. (a) CCS . The significance of CCS as a compliance alternative is several - fold. As a practical matter, it offers 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 th e underlying economics. Also, it offers a vehicle for the continued scaling of CCS, a process that can be expected to lower the costs of CCS in the future. In addition, this compliance alternative provid es further support for the reasonableness of the EPA’s proposals in this rulemaking to combine the Da category and a portion of the KKKK category and to determine that a NGCC facility is the “best system of emission reduction.” This is because this complia nce alternative, by 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 power plant industry. CCS as a compliance alternative does not achieve these goals by necessarily qualifying , under the CAA section 111(a)(1) definition of “standard of performance,” as the “best system of emission reduction which (taking into account cost [and other factors]) the Admi nistrator determines has been adequately demonstrated.” Instead, this compliance alternative is feasible and sufficiently available**02/2 8** **/2012 Draft**

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Page **126** of **233** for the limited amount of new coal - fired construction that is expected , 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 present 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 Federal 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. We note that the need for governmental subsidies to reduce the costs of CCS is hardly unique in the electricity generation sector . Each of the major types of energy used to generate electricity has been or is currently supported by some type of government subsidy -- such as tax ben efits, loan guarantees, low - cost leases, or direct expenditures -- for some aspect of development and utilization, ranging from exploration to control installation. This is true of fossil - fuel - fired ; as well as nuclear - , geothermal, wind - , and solar genera ted electricity . These subsidies have been designed to overcome cost barriers to the utilization of the energy . In this context, the**02/2 8** **/2012 Draft**

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Page **127** of **233** need for subsidies for CCS to overcome cost barriers does not mean that CCS cannot be considered an alternative compliance method in this rulemaking. Second, it is reasonable to expect that some coal - fired power plants may be able to implement the supercritical efficiency standard for an initial period of time ( the first 10 years) and then implement CCS and achie ve lower 12 - month rolling average rates after that, so that the source achieves the 1,000 lb CO 2 /MWh standard on average over the 30 - year period following construction. 61 This is because, again, CCS is feasible and can be expected to be sufficiently available

– in light of continued subsidies and lower future costs

– in light of the limited demand . Third, although we do not propose tha t the 30 - year compliance option meets the definition of the “best system of emission reduction [(BSER)] ... adequately demonstrated,” under CAA section 111, we note that identifying CCS as a compliance option based in part on the expectation that CCS will cost less in the future is consistent with the section 111 requirements for determining the BSER adequately demonstrated . In determining what emissions controls qualify as the BSER adequately demonstrated

– which must take costs into account

–
61 Note that under today’s proposed rulemaking, the 30 - year averaging proposal is associat ed only with the implementation of CCS. This proposal does not allow 30 - year averaging for any other purpose.**02/2 8** **/2012 Draft**

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Page **128** of **233** 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 future developments
– - as long as supported by an adequate record

– - in determining whether a particular system of emission reduction is the BSER adequately demonstrated’ 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 determin ing the BSER adequately demonstrated :

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 t hrough the application of 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 pol lution 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). A s quoted, this statement makes clear that a standard of performance may be based on a**02/2 8** **/2012 Draft**

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Page **129** of **233** technology that is not “in actual routine use somewhere,” but that “normally can be made available.” Moreover, the technology need not be available until “a time which th e 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 stated, in Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973): We begin by rejecting the suggestion of the cement manufacturers that the Act's requirement that emission limitations be "adequately demonstrated" nec essarily 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 present, 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 to 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 **. 62**  Id. at 391 (emphasis added). Again, although these statements in the legislative history and case law are in the context of establishing the basis for a standard of performance, the same principle

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Page **130** of **233** the EPA may reasonably project the path of technological development

– - supports treating CCS as a compliance alternative. Although, for the reasons noted above, we do expect the costs of CCS to decline, we recognize that the amount of the decrease is uncertain . Even so, the presence of cost uncertainty by itself does not mean that prosp ective power plants cannot be expected to adopt the 30 - year alternative compliance option . We note that prospective power plants face significant cost uncertainties in any event . For example we note that recently, several owner/operators have announced that they do not intend to construct coal - fired power plants without CCS . They have explained that they anticipate more widespread CO 2 control requirements in the future, so that constructing coal - fired plants at this time without CCS could leave them subj ect to liability for high retrofit control costs in the future . This sentiment indicates that some sources may avail themselves of the alternative compliance option. The inclusion of an alternative compliance option has precedent in EPA rulemaking under t he CAA . In the past, the EPA has promulgated rules that adopt an emission limit based on a particular technology (such as, in the present rulemaking, NGCC), but has supported that action on grounds that sources have compliance alternatives, even though higher priced . Examples include: “Finding of Significant**02/2 8** **/2012 Draft**

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Page **131** of **233** Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone: Final Rule” 63 FR 57356, 57378 (Oct. 27, 1998) (in t he rule that became known as the “NOx SIP Call,” the EPA based NOx emission limits that states were required to meet on the assumption that states could adopt specified control measures that were “highly cost - effective,” but the EPA identified other contro l measures that, even though not as cost - effective, the states could adopt instead); (b) 30 - year P eriod . We propose a 30 - year period because we generally expect that ten years provides sufficient time either for owners/operators who are interested in considering cost improvements that occur as a result of the lessons learned from early adopters, or provides early adopters sufficient time to address any startup challen ges. (c) Supercritical Efficiency Level . According to the Depart of Energy Cost and Performance Baseline for Fossil Energy Plants reports, the use of supercritical steam is the most cost effective option for new conventional coal - fired generation and results in the lowest overall costs . In addition, the increased efficiency results in reduced cooling water requirements and reduced environmental impacts associated with coal mining, delivery, and handling. Furthermore,**02/2 8** **/2012 Draft**

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Page **132** of **233** climate change impacts result f rom the cumulative amount of emissions so reduced near term emissions provide additional benefits. Therefore, considering the benefits and minimal, if any, cost of using supercritical steam conditions, as opposed to subcritical steam conditions, we have co ncluded that an annual standard based on the best performing conventional coal - fired generation is appropriate. There are a dozen bituminous - fired and 2 subbituminous - fired EGUs that have demonstrated the proposed annual standard is achievable on a long t erm basis. Furthermore, We have concluded that with coal drying technology, which is being used on a number of power plants today, the annual standard is achievable by a wide range of units firing a variety of coal types including lignite. There are multi ple vendors that offer processes to upgrade lignite to a heating value that is equal to or greater than subbituminous coals. The best performing subbituminous - fired EGU has maintained a 12 - month emissions rate of 1,730 lb CO 2 /MWh. A new EGU using a similar design would be able to burn upgraded lignite and be incompliance with the proposed annual standard. We solicit comment on all aspects of the alternative compliance option, including the 30 - year averaging option we propose in this action . Although we are not proposing that CCS, including the 30 - year option, does or does not qualify as the BSER adequately demonstrated,**02/2 8** **/2012 Draft**

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Page **133** of **233** we also solicit comment on that issue. B. How did the EPA determine the other requirements for the proposed standards? 1. Compliance Requir ements The proposed compliance requirements, to the extent possible, incorporate monitoring already being performed as part of existing part 60 and part 75 requirements. In addition, we intend to recognize the environmental benefit of electricity generate d by CHP facilities to account for the increased end use efficiency resulting from avoided 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 dist ribution 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 establishing a shorter averaging 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 conditions,**02/2 8** **/2012 Draft**

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Page **134** of **233** allows consistent emissions rate averaging, allows for a more protective standard and decreased compliance burden, and simplifies compliance for state permitting aut horities. 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. The EPA proposes that it is not necessary to have a shorter averaging period for CO 2 from these sources because 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 p ollutant concentrations. 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 Modificati ons 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**02/2 8** **/2012 Draft**

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Page **135** of **233** 60.14(e). Available information does not provide an adequate basis for the EPA to develop proposed standards of performance for modifications. That is because the types of projects that these EGUs are most likely to undertake t hat 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 types of projects are specifically exempted from the definition of “modifications” under 40 CFR 60. 14(e)(5) . In contrast, based on past experience, we expect no more than a relatively small number of actions that do constitute modifications, and we expect them to be from different types of sources and to take different forms . In light of this, th e EPA does not have sufficient information to develop standards of performance for modifications, and therefore the EPA is not proposing any standards for modifications. As a result, EGUs that undertake pollutio n control projects or other physical or operational changes would continue to be treated as existing sources . 2. Statutory and Regulatory Requirements Clean Air Act section 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 “exist ing source[s]” in a category regulated for that pollutant under section**02/2 8** **/2012 Draft**

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Page **136** of **233** 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 (o r, if earlier, proposed 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.” Clean Ai r 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 amount of any air pollutant emitted by such source or which results in the emission of any air pollu tant not previously emitted.” The EPA’s regulations provide that under CAA section 111(a)(4), 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 ...:

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Page **137** of **233** (5) The addition or use of any system or device whose primary function is the reduct ion 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 change 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 c ontrol equipment or systems. 3. The EPA’s Proposed Course of Action We expect EGUs to undertake changes in the foreseeable future that would increase their maximum achievable hourly rate of CO 2 emissions . We expect that the most of those actions would constitute pollution control projects. In many cases, those projects would involve the installation of add - on control equipment required to meet CAA requirements for conventional air pollutants. We expect that these increases i n CO 2 emissions would occur as a chemical byproduct of the operation of the control equipment, and would be small. In other cases, those projects will involve equipment changes to meet the requirements of this rulemaking and that may have the effec t of increasing the sources’ maximum hourly achievable emission rate, even while decreasing actual emission rate. Because such actions would be**02/2 8** **/2012 Draft**

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Page **138** of **233** treated as pollution control projects under the EPA’s current NSPS regulations, they would b e specifically exempted from the definition of modification . Aside from pollution control projects, in the past, there have also been a small number of instances, on an annual basis, in which power plants have undertaken actions t hat , in the EPA’s view, should be treated as modifications . The sources that took these actions vary widely, one from another, depending on, among other things, size, fuel type, and physical plant conf iguration . The diversity of sources undertaking modifications has reflected the diversity among power plants as a whole. Moreover , the types of modifications they have undertaken have also varied widely . Because of the small number of modifications, their disparate nature, and the disparate type of sources, we do not at present have an adequate base of information to propose standards of performance for modifications . For example, we do not have adequ ate information as to the types of physical or operational changes sources may undertake or the amount of increase in CO 2 emissions from those changes . Nor do we have adequate informa tion as to the types of control actions sources could take to reduce emissions, including the types of controls that may be available or the cost or effectiveness of those controls . The most likely candi dates for control actions**02/2 8** **/2012 Draft**

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Page **139** of **233** would be efficiency measures and we do not have adequate information as to the types of sources and types of changes at issue that could provide the basis for a proposal for efficiency measures . If a larger number of facilities of a particular type had undertaken modifications of a particular kind, the EPA may be able to develop a standard of performance for that type . But, as noted, that is not the case here. As a result, in this action , the EPA is not proposing standards of performance for modifications. The EPA is soliciting comment on the types of sources that may be expected to undertake modifications, the types of modifications, the t ypes of control measures, and all other aspects of this issue . This solicitation of comment is in the nature of an advance notice of proposed rulemaking . If we receive sufficient additional information, we may issue a proposal for modifications in the futu re . However, to reiterate, we are not proposing any standards of performance for these modifications at this time . Accordingly, the EPA does not expect to promulgate any standards of performance for modifications when it takes final action on this rulemaki ng. 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**02/2 8** **/2012 Draft**

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Page **140** of **233** or final “standard of performance under this sectio n which will be applicable to such source.” CAA section 111(a)(2) . Accordingly, if there is no proposed or promulgated standard of performance applicable to a particular source, then the source cannot be considered a “new source ” and therefore will not be subject to any standards of performance we finalize for new sources. Further, under the definitional provisions, any source that is not a “new” source is an “existing source .” CAA section 111( a)(6). Therefore, affected EGUs that undertake modifications will continue to be treated as existing sources . In the future, they 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 , under CAA section 111(d). 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 be tween 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**02/2 8** **/2012 Draft**

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Page **141** of **233** 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 action, if any, would be appropriate for the EPA to take. B. Requirements for Tr ansitional Sources 1. Overview In today’s proposed rulemaking, the EPA is not proposing a standard of performance for proposed coal - fired power plants that have received an approved PSD permit by (including sources who have approved permits that a re in the process of being amended, if those sources are intending to install CCS as evidenced by participating in any of the DOE CCS funding programs (either loan guarantee or grant programs)) , and that commence construction within a year after, the date of this proposal We call these sources “transitional sources ” and, for convenience, we call all new sources that are subject to the standard of performance we propose in this rulemaking “n on transitional sources.” The EPA is aware of approximately 1 5 sources that could potentially qualify as transitional sources because they have obtained PSD permits but have not yet commenced construction, although many are not expected to commence construction within the
one - year period. Of these, six have indicated that they intend to**02/2 8** **/2012 Draft**

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Page **142** of **233** install CCS (and in most if not all cases are participating in DOE CCS programs). These five projects are: The Texas Clean Energy Project in Texas, the Trailblazer project in Texas, the Ta ylorville project in Illinois, the Good Spring facility in Pennsylvania, the Power County Advanced Energy Center in Idaho and the Cash Creek Generation Plant in Kentucky. The remaining nine plants without CCS are: Limestone 3, White Stallion and Coletto C reek in Texas, Holcomb 2 in Kansas, James De Young and Wolverine in Michigan, Washington County in Georgia, Bonanza in Utah, and Two Elk in Wyoming. Without this different treatment, a transitional source would be subject to the new source standard of performance when it does commence construction, even though it has already incurred costs to receive a PSD permit, often times, purchased land and taken other steps preparatory to commence construction in the very near future, but in at least some cases has not attempted to incorporate the controls that the EPA would now be requiring for new coal - fired EGUs under the
new source standard of performance. In this event, the high costs of possibly relocating the project, revising its permit and other plans to meet the standard of performance could well oblige the proposed EGU to, in effect, start over, so that its prior expenditures would be lost.**02/2 8** **/2012 Draft**

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Page **143** of **233** As a result, we consider that the costs to the transitional sources of complying with the standard of performance to be significantly higher than for non - trans itional sources, and therefore we do not consider that standard of performance to be appropriate for transitional sources. Rather, we consider that CO 2 emissions from transitional sources should be limited only to the extent that they would be limited as t he source complies with its PSD permit. This approach is consistent with the costs faced by transitional sources. It is also consistent with principles of equitable treatment of transitional sources. In addition, it helps to assure the reliability of the e lectrical system by allowing some of the plants that the industry had intended to go forward to go forward. 2. Requirements for Transitional Sources In this action, we make clear that our proposed standard of performance for non - transitional sources is not applicable to transitional sources, which we define as coal - fired power plants that have received approval for their complete PSD preconstruction permits by the date of this proposal, and that commence construction within a year of date of this proposal. 64 Although transitional sources would

64 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 propo sal. Because they**02/2 8** **/2012 Draft**

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Page **144** of **233** not be subject to CO 2 emissions controls under CAA section 111, they would be subject to CO 2 emissions limits due to any CO 2 limits in the source’s PSD permit. If the source received the permit prior to January 2, 2011, the permit may not include CO 2 limits. In this case , as a practical matter, CO 2 emissions would be limited by whatever design or operating constraints are imposed on the source under the PSD permit. For example, if the PSD permit requires that the source be constructed at a supercritical level of efficiency, then CO 2 emissions can be expected to be limited to approxima tely 1800 lbs CO 2 /MWh because, as noted, that is the level of CO 2 emissions associated with that type of EGU. For purposes of this treatment of transitional sources, the date of this proposal is the date of publication in the Federal Register of this prop osed notice of 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. We also note that because transitional sources would not be subject to any pr oposed standard of performance, they would not be considered “new source[s],” under CAA section 111(a)(2). Instead,

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.**02/2 8** **/2012 Draft**

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Page **145** of **233** they would be considered to be “existing source[s],” under section 111(a)(6). As a result, they would be subject to any requirements promulg ated for existing sources under section 111(d) and related state plans. 3. EPA Policy As noted, the EPA proposes that non - transitional source fossil fired power plants that commence construction after the date of proposal are subject to the standard of 1,000 lbs CO 2 /MWh, and the EPA proposes to base this standard on the EPA’s identification of natural gas combined cycle (NGCC) as the “best system of emission reduction . . . adequately demonstrated.” CAA section 111(a)(1) (BSER). Commenters have pointed o ut that there is a group of proposed coal - fired power plants that, by the date of this proposal, will have already received PSD permits and that may have taken other action preparatory to constructing (including purchasing land) such that they are poised t o commence construction in the very near future. The EPA is aware that owners or operators of approximately 1 5 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 (discussed below). S ix of these newly proposed EGUs have indicated they intend t install CCS , and the remaining ones have not. Available information indicates that a small**02/2 8** **/2012 Draft**

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Page **146** of **233** number of these sources have taken additional preconstruc tion steps and therefore may be in a position to commence construction in the very near future. For instance, several sources have signed contracts for electricity, CO 2 , or other products. For instance, the Texas Clean Energy Project has contracts for its CO 2 , and electricity and also has contracts to sell urea . 65 It is the policy of the EPA that this small group of transitional sources should be treated as separate and distinct from the other proposed or future power plants, that is, the non transitional sources, which are much greater in number, and for which we propose the 1,000 lb CO 2 /MWh standard. As we explain elsewhere, in justifying this proposed standard, owners or operators contemplating construction of non - transitional base - load power plants have choices: they can choose the type of facility and therefore may construct either a NGCC plant or a coal - fired plant, and if they choose the latter, they have choices as to siting and other considerations so as to be able to install CCS. As a result, for t hese sources, NGCC constitutes the BSER, and the 1,000 lbs CO 2 /MWh emission limit reflects that BSER and therefore is the appropriate standard of performance under section 111. Moreover, as a policy matter, for those that choose to construct a coal - fired u nit, they may choose to

65 http://www.texascleanenergyproject.com/news
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Page **147** of **233** construct the plant in a place and a manner that allows installation of CCS, either at the time of construction or, in accordance with the 30 - year averaging proposal, some years down the road. In contrast, transitional sources are d ifferently situated. They have already incurred substantial costs in permitting and taking other steps preparatory to commencing construction as coal - fired power plants, often including purchasing land for the new facility, in most cases without CCS. Count ing these sunk costs, converting their plant to NGCC would be more expensive than for non - transitional sources, and as a result, NGCC does not constitute the BSER for them. As for CCS, for the transitional sources that are not designed for CCS, as a practi cal matter, it would be challenging for such a source to proceed with construction without substantial re - design of the project in order to install CCS and thereby be in compliance with the 1,000 lbs CO 2 /MwH standard. There are several 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 th e original project design, space considerations may make it difficult to accommodate in the facility’s design. Third, the requirement to use CCS could necessitate a change in the very generation technology that a source may choose to use. For instance,**02/2 8** **/2012 Draft**

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Page **148** of **233** i nstead 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 account 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. It bears emphasis that the requirements created by the new source standard in today’s action are fundamentally different from post - combustion controls required to meet new source standards for conventional pollutants . Those controls could be much more easily redesigned into a planned plant without changing the plant’s 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 stage and is very close to commencing construction than it would be in other types of projects . Considerations in addition to costs also support our treatment of transitional sources. These include equitable considerations:**02/2 8** **/2012 Draft**

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Page **149** of **233** Transitional sources have incurr ed significant expenses and undertaken a long planning period, as a result they have more invested in their current plans, and as a result of all that, they have an equitable claim to being allowed to proceed without requirements other than those in their PSD permits. These considerations also include promotion of the reliability of the electricity system. Owners or operators of transitional sources have planned them and are on the verge of commencing construction of them because they perceive a demand for the electricity the sources would generate. The EPA’s modeling of the electricity industry in the foreseeable future forecasts a potential reduction in supply as older coal - fired EGUs are retired. Allowing these few transitional sources to proceed as plann ed

– including generally on the time schedule planned -- would promote reliability. As noted, we propose to define transitional sources to include sources that, besides having a complete PSD permit by the date of proposal, commence construction within 12 months of the date of proposal. This one - year period gives effect to the policy of limiting transitional source treatment to sources that, as of the date of proposal, have incurred the expenses necessary so that they are poised to commence construction in t he very near future. In light of the complex of requirements, which range from siting to financing,**02/2 8** **/2012 Draft**

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Page **150** of **233** needed to commence construction of the large and expensive type of project that a power plant is, any proposed source that does commence construction within the relatively short period of 12 months of the date of proposal qualifies as having been poised to commence construction as of the date of proposal. It is those sources that would be most disadvantaged by being subjected to the standards of performance p roposed in today’s rulemaking. On the other hand, 12 months is long enough to give transitional sources a reasonable period to commence construction in accordance with the terms of their permit. Any proposed source that does not commence construction within 12 months cannot be said to be similarly situated. Finally, as a matter of policy, a lthough transitional sources would not be subject to the 1,000 standard lbs CO 2 /MWh for new sources, it is the EPA’s policy that transitional sources would become subject to the requirements the EPA intends shortly to promulgate for existing sources. 4. Legal approach In this section, we describe our legal approach for implementing the transitional source policy. First, we note that we considered the approach of treating transitional sources as a separate subcategory and proposing a standard of performance for them at what we call a “no - further - control level.” For practical reasons that we describe,**02/2 8** **/2012 Draft**

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Page **151** of **233** we rejected this approach. Second, we discuss our basis for the approach we are taking, which is to not propose a standard of performance for these sources. We discuss the re levant CAA section 111 requirements and our interpretation of them, and we then apply that interpretation to our approach. a. Consideration of approach of separate standard of performance . The EPA considered treating transitional sources as a separate subc ategory of new sources and proposing a standard of performance for that subcategory. Under CAA section 111(b)(2), discussed further below, the EPA is authorized to subcategorize sources within categories of new sources to establish standards of performance . In this case, the EPA may well have proposed, in light of the transitional sources’ sunk costs, that the BSER for these sources would be the controls to which they would be subject under the terms of their PSD permits, and no further controls under secti on 111. 67 The EPA would then have determined the emission rate for each transitional source that reflected that source’s level of CO 2 emissions in accord with the terms of its PSD permit. This emission rate would have constituted the “no - further - control” st andard of

67 This type of standard of p erformance could take one of several different forms, such as a standard that would not limit the source’s CO2 emissions, or a standard that the transitional source itself would identify as equaling the emission limit it would achieve through compliance wi th the applicable terms of its permit.**02/2 8** **/2012 Draft**

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Page **152** of **233** performance. Note that under this approach, each transitional source would have received an emission limit distinct to that source. However, this approach would give rise to practical problems: As noted, many of the 15 potential transitional sources have a PSD permit that does not regulate CO 2 because GHGs were not subject to PSD until the January 2, 2011 effective date of the first regulatory action controlling CO 2 emissions under the CAA. Particula rly for those sources, this approach could have created uncertainty as to what the EPA would promulgate as the emission rate in the final standard of performance. This is because since these sources’ permits do not specify a CO 2 limit, the EPA would have t o develop limits based on the design of the unit (including the project’s type of technology and fuels) ; the EPA does not have all the information necessary to make such determinations at this time. In addition, all transitional sources, even those whose P SD permits do establish a CO 2 limit, would face uncertainty as to what final standard the EPA would promulgate. This uncertainty would stem from (i) the possible wide range of design of transitional sources and the consequent complexity of the EPA’s task, coupled with the relatively short (12 - month) period of time for rulemaking, in establishing an individual standard of performance for each source; and (ii) the fact that the public could well comment on the proposed**02/2 8** **/2012 Draft**

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Page **153** of **233** standard of performance and the EPA, based on those comments, could finalize standards of performance different than proposed, which may be more difficult for the transitional sources to meet. The uncertainties that the sources could experience as to what the final standards of perf ormance would entail could well deter those sources from commencing construction until the EPA promulgated the final standard of performance. Such delay would defeat the policy underlying the EPA’s approach to transitional sources, which is to allow these sources favorable treatment only if they commence construction within 12 months of proposal. If they are deterred from commencing construction until after the final rule, they may have lost that 12 - month window. We have other concerns besides these practi cal problems over the approach of treating transitional sources as a subcategory of new sources and establishing a standard of performance for them. This approach would provide little, if any, environmental benefit because the standard of performance would not provide further control beyond the limits of the sources’ PSD permits. In fact, this approach could be detrimental from an environmental standpoint because by treating the transitional sources as new sources, the EPA could not treat them as existing s ources and as a result, could not subject them to**02/2 8** **/2012 Draft**

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Page **154** of **233** possible regulation under the existing source standard that the EPA expects soon to promulgate. b. Adoption of approach of not proposing a standard of performance . In light of the practical difficulties jus t described, the EPA is not proposing any standard of performance applicable to transitional sources. As a result, by the terms of CAA section 111, these sources cannot be treated as new sources and therefore cannot be subject to a new source standard of p erformance under CAA section 111(b). Instead, they would remain subject to the constraints imposed by their PSD permits. In addition, they would be considered to be existing sources, and therefore in the future, they would be subject to any requirements th e EPA may promulgate for existing sources under CAA section 111(d). This approach is consistent with the provisions of CAA section 111. ( 1 ) . Key provisions of CAA section 111 . The key provisions of CAA section 111, for present purposes, are as follows: Und er section 111(b)(1)(A), as the first step in the process of promulgating regulations under section 111, the Administrator must “publish ... a list of categories of stationary sources.” Then, the Administrator must “[propose] ... Federal standards of perfo rmance for new sources within [the source] category,” and then “promulgate ... such standards with such modifications as he deems appropriate.” Section**02/2 8** **/2012 Draft**

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Page **155** of **233** 111(b)(1)(B). Section 111(b)(2) goes on to provide that “[t]he Administrator may distinguish among class es, types, and sizes within categories of new sources for the purpose of establishing such standards.” A “new source” is defined as “any stationary source, the construction or modification of which is commenced after [EPA proposes] a standard of performanc e ... which will be applicable to such source.” Section 111(a)(2). 68 Once the Administrator promulgates standards for new sources under CAA section 111(b), the Administrator must take action under CAA section 111(d) to establish requirements for “any exis ting source for any air pollutant (i) [that falls into specified categories] but (ii) to which a standard of performance under this section would apply if such existing source were a new source....” Section 111(d)(1). An “existing source” is defined as “an y stationary source other than a new source.” Section 111(a)(6).

68 The CAA does not include a definition of the term “commenced” for these purposes, but the EPA framework regulations promulgated under section 111 define this term 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.**02/2 8** **/2012 Draft**

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Page **156** of **233** ( 2 ). Interpretation of key provisions of CAA section 111 . The EPA interprets these provisions as follows: Under section 111(b)(1)(B),
once the EPA lists a category of sources, the EPA is required to propose and promulgate standards of performance for new sources in that category. The EPA is not, however, required to promulgate standards of performance that cover all new sources. This is clear from the directive in section 111(b)(1)( B), which requires that the EPA propose standards of performance “for new sources” within the category, but does not require that the EPA propose such standards for all new sources or for any new source. The EPA may fulfill that directive by proposing stan dards that cover some, but not all, sources that newly commence construction or modification. Similarly, the term “new source” in section 111(a)(2) is defined to incorporate the limitation that the EPA must propose or promulgate a standard applicable to t he source for the source to be considered “new.” That is, section 111(a)(2) defines a “new source” as any source for which construction or modification commences after the EPA proposes “a standard of performance ... which will be applicable to such source. ” By its terms, this provision contemplates that the EPA may not propose a standard of performance applicable to certain sources, and that if the EPA does not, those sources would not be**02/2 8** **/2012 Draft**

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Page **157** of **233** considered to be “new source[s]” and therefore not subject to any new source standard of performance. In fact, in a number of prior rulemakings under section 111, the EPA has limited the applicability of its proposed and final standards of performance to certain groups of new sources, and has not attempted to cover all sour ces that newly commence construction or modification. For example, one of the first categories of sources that the EPA regulated under section 111 was fossil - fired power plants, but from the beginning, the EPA imposed an emissions threshold, so that source s that newly commence construction or modification but that emit below that threshold would not be subject to any standard of performance. Similarly, in other section 111 rulemakings, the EPA has proposed and promulgated rulemakings that apply standards of performance to certain emission units in a category, but not to all of those emission units. In some cases, the EPA has subsequently proposed or promulgated additional rulemakings that apply standards of performance to more of the emission units in the ca tegory. Section 111(b)(2) authorizes the EPA to “distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standards.” In other words, once the EPA selects the set of sources for which to propose reg ulations, the EPA**02/2 8** **/2012 Draft**

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Page **158** of **233** may establish subcategories among those new sources and promulgate different standards for those subcategories. Strictly speaking, this authorization to subcategorize is limited to “new sources,” which, again, are sources newly commencing construction or modification and for which the EPA proposes or promulgates a standard of performance; and this authorization to subcategorize does not apply in the case of sources that are not “new sources” because the EPA does not propose or promulgate a standard of performance applicable to them. Any source that is not a “new source”

– either because of the time that it commences construction or modification or because the EPA has not proposed or promulgated a standard of performance applicable to it

– i s considered an existing source, under section 111(a)(6). In general, existing sources of certain pollutants are subject to requirements that the EPA promulgates under section 111(d). ( 3 ). Application to transitional sources . In this action, the EPA is not proposing a standard of performance for transitional sources and as a result, by the terms of CAA section 111, transitional sources would not be considered new sources and therefore would not be subject to any standard of performance for new sou rces. In contrast, the EPA is proposing a standard of performance for non - transitional sources, one that is based the EPA’s proposed determination that NGCC**02/2 8** **/2012 Draft**

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Page **159** of **233** is the BSER for those sources, and, as a policy matter, that for coal - fired EGUs, CSS is a complian ce option. As noted, the record that supports this proposal for non - transitional sources is based on the costs of those controls to those sources. Transitional sources have different cost considerations because of the costs they have already incurred to o btain their PSD permits and to take whatever other steps necessary for them to commence construction in the very near future. 69 These cost considerations support the EPA’s policy that transitional sources should remain subject to whatever CO 2 emission limit s are included in, or result from compliance with, their PSD permits, but that no further control of CO 2 under the new source provisions of CAA section 111(b) is merited. The EPA is not actually subcategorizing transitional sources under 111(b)(2) because by its terms that provision authorizes subcategorizing only for new sources (that is, sources for which the EPA proposes a standard of performance). Nor is the EPA proposing a
no - further - control standard of performance because, as noted, of the

69 EPA intends that its treatment of transitional and non - transitional sources is severable from each other and considers that severability is logical because of the reco rd - based differences between the two types of sources and because there is no interdependency in EPA’s treatment of the two types of sources. This statement concerning severability for these components in this rulemaking should not be construed to have imp lications for whether other components in this rulemaking are severable.**02/2 8** **/2012 Draft**

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Page **160** of **233** practical c oncerns that such a standard would deter transitional sources from commencing construction and thereby defeat the policy that transitional source treatment should apply to sources that commence construction within 12 months of the proposal. Even so, the approach that the EPA is taking for transitional sources of not proposing a standard of performance has much the same effect as proposing a no - further - control standard of performance and is supported by the same cost considerations. As noted, other supportin g considerations include equitable and reliability. Our approach of not proposing regulations for transitional sources is consistent with the terms of the provisions of section 111 and is consistent with the purposes of CAA section 111. As noted, under the terms of section 111, the EPA is not required to propose or promulgate standards of performance for all sources in a source category that newly commence construction, and therefore the EPA is not required to propose a standard of performance for transitional sources. Transitional sources are a small group of sources with a distinct profile of costs, CO 2 emissions, and equitable concerns. In any event, the EPA’s approach for these sources is, in key ways, consistent with proposing a standard of per formance for them. As noted, under the EPA’s approach, transitional source would, as a matter of practice, face limits on their CO 2 emissions that stem from**02/2 8** **/2012 Draft**

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Page **161** of **233** either any explicit CO 2 limits in their PSD permit or, if none, the operational limits associated w ith compliance with the terms of their PSD permit. 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 source t o meet the new limits. As noted , 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 desi gned to meet, because efficiency (and thus CO 2 emissions) are an integral part of unit design. We recognize that this approach of not proposing a standard of performance for transitional sources could raise the question of whether this approach is consistent with the requirement implicit i n the definition of “new source” under CAA section 111(a)(2 ) that a source be subject to a standard of performance when it commences construction after the date of proposal for that standard. We believe the approach is consistent with, and does not circumvent, that requirement. As noted, CAA section 111 does not require that all sources that newly commence construction be treated as new sources, and in past section 111 rulemakings, the EPA has not applied the standards of performance that it proposes and promulgates to all sources that newly commence construction in a source category .**02/2 8** **/2012 Draft**

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Page **162** of **233** Moreover, as noted, t ransitional sources are a small group of sources and they have a distinct profile. In addition, we note that section 111 allows other approaches under which the EPA may encourage sources to commence construction as soon as possible and avoid the applicability of a standard of performance. For example, in this case, the EPA could have issued an advance notice of proposed rulemaking (ANPR) stating that the EPA intends to propose a standard of performance for all fossil - fired power plants within 12 months, and further stating that the EPA did not expect to provide any special treatment for coal - fired power plants that as of the date of proposal (again, 12 months hence), had received a PSD permit and taken other action to preparatory for commencing construction , but had not yet commenced construction. This ANPR approach would have had a similar effect, so far as transitional
sources are concerned, as the treatment of transitional sources in today’s rulemaking. However, it would also have had the effect of delaying by 12 months the EPA’s establishment of standards of performance for non - transitional sources. Accordingly, this ANPR approach would not achieve the EPA’s po licy objectives, and the EPA does not take this approach. But the fact that this ANPR approach is consistent with section 111 suggests that the approach that the EPA is taking in this rulemaking is also consistent with section 111.**02/2 8** **/2012 Draft**

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Page **163** of **233** C. Requirements for Rec onstructions 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 s tandards of performance. In today’s rulemaking, we do not propose any standard of performance for reconstructed sources, but we take comment on two options: ( i) not taking final action to establish a new st andard of performance, which, as a practical matter, would mean that reconstructed sources would be treated as existing sources; or (ii) establishing the standard of performance at either the same level as for new sources or at the supercritical efficienc y 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 construct 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), 70 provide that an existing source, “upon reconstruction,” becomes subject to

70 CAA section 111 does not explicitly include provisions for reconstructed sources.**02/2 8** **/2012 Draft**

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Page **1 64**  of **233** the standard of performance for new sources. 40 CFR 60.15(a). The regulations de fine “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 existing source does not increase emissions. In addition, the component replacement constitutes a reconstruction only if it is technologically and economi cally 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 provi de 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 de termine, within a**02/2 8** **/2012 Draft**

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Page **165** of **233** 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 are presently planning any 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. Our reasoning is much the
same as with modifications, which is that the lack of adequate information about the type of source ; the type of changes ; the extent of emissions increases; and the type of control measures, including their cost and emissions reductions, precludes proposing a standard of performance . Instead of issuing a proposal , the EPA solicits comment on all issues related to reconstructions, including the aspects just noted . In addition, we solicit comment on two different options : a . Option 1 : No final action to establish a standard of performance. Under the first option, at the time the EPA finalizes this action, the EPA would not include a standard of performance for reconstructions. This option parallels the option, described above, for modifications . Under this option, as a practical matter, sources**02/2 8** **/2012 Draft**

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Page **166** of **233** undertaking reconstructions after final action 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 require ments that the EPA may promulgate, and states may impose, under CAA section 111(d)(1) . Depending on the information the EPA acquires about reconstructions, the EPA may, in the future, propose and promulgate standards of performance for them. b . Opt ion 2: Establish a standard of performance. Under the second option, at the time the EPA finalizes this action, the EPA would include a standard of performance for reconstructions at, as one sub option, the same emissions level that the EPA finalizes for new sources or, as another sub - option, the 1800 lb/mWH CO 2 supercritical efficiency level. Under this option, sources undertaking reconstructions after the effective date of this action would be treated as new sources and subject to the standard of performance . 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 opt ion may find further support because under the definition of “reconstruction” quoted above, a source’s rebuilding project becomes treated as a reconstruction only if it is “technologically and**02/2 8** **/2012 Draft**

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Page **167** of **233** economically feasible [for the source] to meet the applicable
s tandards.” 40 CFR 60.15(a). The 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 perc ent of the cost of a new source) in an existing EGU to extend its economic life for decades rather than build an entirely new, lower - emitting EGU. The 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 the EPA is not proposing a NSPS for reconstructions, even if the EPA takes final action e stablishing 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 options for reconstru ctions.**02/2 8** **/2012 Draft**

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Page **168** of **233 VI. Implications for PSD and Title V**  **P rograms**  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 111 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

– described below -- continue to apply to the PSD program. This issue arises because States with approved PSD programs in their state implementation plans (SIPs) implement PSD, and most of these States have recently revised their SIPs to incorporate the higher thresholds for PSD applicability to GHGs that the EPA promulgated under what we call the Tailoring Rule . 71 Commenters have queried whether under the EPA’s PSD regulations, promulgation of a section 111 standard of performance GHGs would require these s tates to revise their SIPs again to incorporate the Tailoring Rule

71 “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule; Final Rule,” 75 FR 31514 (June 3, 2010). In the Tailoring Rule, EPA established a process for phasing in PSD and Title V applicability to sources based on the amount of th eir GHG emissions, instead of immediately applying PSD and title V at the 100 or 250 ton per year or thresholds included under the PSD and title V applicability provisions.**02/2 8** **/2012 Draft**

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Page **169** of **233** thresholds again . T he 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 section 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 finalize 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 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 the EPA will shortly proceed with a separate rulemaking action to narrow its approval of all of the State’s approved SIP PSD programs t o assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of today’s proposal.**02/2 8** **/2012 Draft**

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Page **170** of **233** As discussed below, in the case of title V, today ’s rulemaking does not have implications for the Tailoring Rule thresholds 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 requi red to obtain a preconstruction permit. This permit assures that the source meets specified requirements, including application of best available control 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. Regulation of GHG emissions in the Light Duty Vehicle Rule triggered applicability of regulatory requirements to stationary sources under the PSD and title V prov isions of the CAA. Hence, on 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**02/2 8** **/2012 Draft**

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Page **171** of **233** 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. Commenters have queried whether, because of the way that the EPA’s PSD regulations are written, promulgating the rule we propose today may raise questions as to wh ether 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 apply to sources subject to PSD. That is, u nder the EPA’s regulations, PSD appli es to a “major stationary source” that undertakes construction, 40 CFR 51.166(a)(7)(i), and to a “major modification.” 40 CFR 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 st ationary 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).**02/2 8** **/2012 Draft**

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Page **172** of **233** The EPA’s regulations define the term “major statio nary 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 o n 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 pollut ant identified under this paragraph (b)(49)(i) as a constituent or precursor to such pollutant.... (ii) Any pollutant that is subject to any standard promulgated under section 111 of the Act; (iii) Any Class I or II substance subject to a standard promulgat ed under or established by title VI of the Act; (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 po llutants 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.**02/2 8** **/2012 Draft**

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Page **173** of **233** 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 states that apply PSD to GHG - emitting sources may have to revise their SIPs, and do s o quite promptly. However, although the Tailoring Rule thresholds on their face 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 inte rpreted to apply to other terms in the definition of “major stationary source” and in the statutory provision, “major emitting facility.” Specifically, the EPA stated:**02/2 8** **/2012 Draft**

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Page **174** of **233** 3. Other Mechanisms As just described, we selected the “subject to regulation” 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 mechanis m 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 driven b y 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 de finitions, 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 regulat ion.” 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 statutory t erm, “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.**02/2 8** **/2012 Draft**

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Page **175** of **233** Thus, according to the preamble, the definition of “major stationary source” itself already incorporates the Tailoring Rule thresholds, and not jus t 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 first NSP S for GHGs (which, as noted above, triggers the PSD requirement under the NSPS trigger provision in the definition of “regulated NSR pollutant ”). 72 To clarify and confirm that the Tailoring Rule thresholds apply to the section 111 prong of the definition of regulated NSR pollutant, in this proposed rulemaking, the EPA is proposing to r evise the NSPS regulations, although not the PSD regulations, to explicitly make clear that the NSPS trigger provision in the PSD regulations incorporate the Tailoring Rule thresholds.

72 This position reads the regulations to be consistent with the CAA PSD provisions themselves. Under those provisions, PSD applies to any “major emitting facility,” which is defined to mean stationary sources that emit or have the potential to emit “any air pollutant” at either 100 or 250 tons per year, depending on the source category. CAA section 165(a), 169(1). EPA has long interpreted these provisions to apply PSD to a stationary source that emits the threshold amounts of any air pollutant subject to regulation. See Tailoring Rule, 75 FR 31579. Under these provisions, at present, PSD is already applicable to GHGs because GHGs are already subject to regulation, and regulating GHGs under CAA section 111 does not any additional type of PSD trigger.**02/2 8** **/2012 Draft**

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Page **176** of **233** As a result, the EPA believes that states that incorporated the Tailoring Rule thresholds into their SIPs may take the position that they also incorporated the EPA’s interpretation in the preamble that the thresholds apply to the definition “ma jor stationary source.” The EPA requests that all states 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 state 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 e xpects 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 applicable to the source. These permits are generally issued through EPA - approved State title V programs. As the EPA explained in the Tailoring Rule preamble, title V applies to a “major source,” CAA section 502(a), which is defined to**02/2 8** **/2012 Draft**

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Page **177** of **233** 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 o f “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 definition of “subject to regulation.” The EPA described its action as follows in the preamble to the Tailoring Rule:

Thus, EPA is adding the phra se “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 regu lation,” 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 Ai r Act Permitting .” 75 FR 17704. Under this first component, a pollutant “subject to regulation” is defined to mean 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 Memorandum at 4 - 5. To address tailoring for GHGs, EPA includes a second component of the definition of “subject to regulation,” specifying that GHGs are not subject to reg ulation for purposes of defining a major source, unless as of July 1, 2011, the emissions of GHGs are from a source emitting or having the potential to emit 100,000 tpy of GHGs on a CO 2 e basis.**02/2 8** **/2012 Draft**

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Page **178** of **233** 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, does 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 th rough 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. W e 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** A. What are the air impacts? The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. We do**02/2 8** **/2012 Draft**

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Page **179** of **233** not project any new coal - fired EGUs to be built. Accor dingly, the EPA believes that this proposed rule is not likely to produce changes in emissions of greenhouse gases or other pollutants although it does encourage the current trend towards cleaner generation. B. What are the energy impacts? This propo sed rule is not anticipated to have a notable effect on the supply, distribution, or use of energy. As previously stated, we believe that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal b ecause of existing and expected market conditions. In addition, we do not project any new coal - fired EGUs to be built. C. What are the compliance costs? The EPA believes this proposed rule will have no compliance costs associated with it, because elec tric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. The EPA does not project any new coal - fired EGUs to be built. D. How will this proposal co ntribute to climate change protection? As previously explained, 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 persis t in the atmosphere for time periods ranging**02/2 8** **/2012 Draft**

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Page **180** of **233** from decades to millennia, depending on the gas. 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 larges t individual sources are in this source category. 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 risks. E. What are the economic and employment impacts? The EPA does not anticipate that this 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 conditio ns 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. F. What are the benefits of the proposed standards? As previously stated, the EPA does no t 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**02/2 8** **/2012 Draft**

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Page **181** of **233** the rule. Therefore, there are no direct monetized climate benefits in terms of CO 2 emiss ion reductions associated with this rulemaking. **VIII. 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 and/or distillate oil. In addition, we are requesting comment on requiring the use the following measurement procedures in condu cting 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 represe ntative 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 - method - ctm - 041.pdf ) to acc ount for wall effects on**02/2 8** **/2012 Draft**

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Page **182** of **233** 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 accuracy determinations and f or 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 ambient air argon concentrati on of 0.93 percent 73 and a molecular weight of 39.9 lb/lb
- mol in calculating the dry gas molecular weight. e. Measure the stack diameter at the CEMS measurement site and the reference method sampling site with a laser distance measurement 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 measurements, both CEMS syst em 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 point. All calculations i nvolving pi would use a value of 3.14159.

73 http://www.physicalgeography.net/fundamentals/7a.html .**02/2 8** **/2012 Draft**

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Page **183** of **233** 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 measurement 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 determinations or for performance te sting. Coal refuse . Due to the multiple environmental benefits of remediating coal refuse piles, we are considering and requesting comment on subcategorizing EGUs that burn over 75 percent coal refuse on an annual basis. As part of the GHG listening sessio ns, 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 e missions in the long term and emissions 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 exposure to atmospheric oxygen and pressure promotes heat - ge nerating reactions, primarily oxidation of the mining waste itself (i.e., the coal refuse piles are slowly**02/2 8** **/2012 Draft**

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Page **184** of **233** burning). This process emits CO 2 and other air pollutants. Remediation 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 th e decimal for each location. By way of example, the coordinates for the monument next to Zachary Taylor’s tomb in Louisville, KY are 38.279401 latitude and - 85.643751 longitude. Combined Heat and Power . We are also considering and requesting comment on if exempting all CHP facilities 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, the 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 al ready exempts CHP sources that primarily generate on - site power.**02/2 8** **/2012 Draft**

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Page **185** of **23 3**  Therefore, as 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 s ell 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 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 avoid 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. 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 t han gross output from the power producer. Net output is the combination of the gross electrical 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 p owered by electricity, steam, hot water, or directly by the gross output of the electric generating unit that does not contribute electrical, mechanical, or thermal output. In general, less than 7.5**02/2 8** **/2012 Draft**

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Page **186** of **233** 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 fuels that require less emissions control equipment, and 3) recognizing the environmental benefit of higher efficiency motors, pumps, and fans. In addition, use of a gross outpu t - based standard could potentially drive the installation of electrically driven feed pumps instead of steam driven feed pumps, even though from an overall net efficiency basis, it may be more efficient to use steam - driven feed pumps. Further, monitoring n et 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.
Simple Cycle Turbines . As stated 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 sta tionary combustion turbines used for peaking operations (i.e., simple cycle turbines). We are considering and requesting**02/2 8** **/2012 Draft**

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Page **187** of **233** comment on not including a definition of simple cycle turbines in the final rule. The potential electric output requirement in the de finition of electric generating unit would already exclude facilities with permit restricting limiting operation to less than 1/3 of their potential electric output, approximately 2,900 hours of full load operation annually. The peaking season is generally considered to be less than 2,500 hours annually, and we are requesting comment on if the capacity factor exemption is sufficient such that specifically exempting simple cycle turbine is unnecessary. We are also requesting c omment on whether the exemption would provide a perverse incentive to build less efficient simple cycle combustion turbines in order to avoid applicability with the proposed rule. While few existing simple cycle turbines presently generate greater than 1/3 of their potential electric output for sale, we are requesting comment on whether the exemption for simple cycle turbines would result in the greater use of simple cycle turbines for intermediate load applications when more efficient combined cycle facili ties would have otherwise been built . In addition, it is our understanding that combined cycle facilities are sometimes built in stages with the combustion turbine engine installation occurring first and the heat recovery steam generator being installed in later years as electricity demand increases. We are requesting comment on**02/2 8** **/2012 Draft**

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Page **188** of **233** whether the exemption would potentially delay the installation of the heat recovery steam generator portion o f new combined cycle facilities. Finally, i n the event we use the defini tion approach in the final rule , we 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. Statutory 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, the 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, the EPA prepared an analysis of the potential costs and benefits 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.**02/2 8** **/2012 Draft**

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Page **189** of **233** 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 proposal because of existing and expected market conditions. B. Paperwork Reduction Act As required by the Paperwork Reduction Act (PRA), 44 U.S.C . 3501 et seq. **,** an information collection request (ICR) will be prepared by the 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 the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. 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 required by this proposed rule is already collected and**02/2 8** **/2012 Draft**

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Page **190** of **233** 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 methods for minimizing respondent burden, including the use of automated collection tec hniques. The EPA has established a public docket for this proposed rule, which includes this ICR, under Docket ID number EPA - HQ - OAR - 2011 - 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 Flexibility 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. Smal l entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, small entity is defined as:**02/2 8** **/2012 Draft**

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Page **191** of **233** (1) A small business that is defined by the SBA’s regulations at 13 CFR 121.201 (for the electric power generation industry, the small business size standard is an ultimate parent entity defined as having a total electric output of 4 million MWh or less in the previous fiscal year. The NAICS codes for the affected i ndustry 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 enterpris e which is independently owned and operated and is not dominant in its field. **Table 4. Potentially Regulated Categories and Entities 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 921150 Fossil fuel electric power generating**02/2 8** **/2012 Draft**

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Page **192** of **233** Government 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, st ate, or local government - owned and operated establishments are classified according to the activity in which they are engaged. After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a signi ficant economic impact on a substantial 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 regulate.'" (citing Motor & Equip. Mfrs. Ass'n. v. Nichols, 142 F.3d 449, 467 (D.C.Cir.1998) (quo ting 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 states 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**02/2 8** **/2012 Draft**

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Page **193** of **233** 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 cooperatives) that will be affected by this rule. In light of this interest, the EPA determined to seek early input from re presentatives of small entities while formulating the provisions of this proposed regulation. Such outreach is also consistent with the President’s January 18, 2011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, which emphasizes th e important role small businesses play in the American economy. This process has enabled the EPA to hear directly from these representatives, at a very preliminary 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.**02/2 8** **/2012 Draft**

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Page **194** of **233** 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 overview of affected so urces 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 entities, and a summary of the listening sessions. We met with eight of the small entity represen tatives, as well as three participants from organizations representing power producers, on June 17, 2011, to discuss the outreach materials, potential requirements 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 e ntity 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 limit ed opportunities for efficiency**02/2 8** **/2012 Draft**

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Page **195** of **233** 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. 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 A ct 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 contai ns no regulatory requirements that might significantly or uniquely affect small governments.**02/2 8** **/2012 Draft**

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Page **196** of **233** Consistent with the intergovernmental consultation provisions 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 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 States. 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 purpose s 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 impro vements 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**02/2 8** **/2012 Draft**

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Page **197** of **233** 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 Confer ence of State Legislatures. In that letter, the National Conference of State Legislatures urged the EPA to ensure that the choice of regulatory options maximizes benefit and minimizes implementation and compliance costs on state and local governments; to p ay particular attention to options that would provide states with as much flexibility as possible; and to take into consideration the constraints of the state legislative calendars and ensure that sufficient time is allowed for state actions necessary to c ome into compliance. The EPA offered consultation to 584 tribal officials early in the process of developing this proposed regulation. Consultation/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 discus sion in this**02/2 8** **/2012 Draft**

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Page **198** of **233** 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 St ates, or on the distribution of power and responsibilities 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 n ot 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 con sistent 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 India n Tribal Governments**02/2 8** **/2012 Draft**

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Page **199** of **233** Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) the 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 tr ibal governments, or the EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement . The 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 a ware 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 addresses 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 tribal officials early in the process o f developing this proposed regulation to permit them to have meaningful and timely input into it s development. Consultation letters were sent to 584**02/2 8** **/2012 Draft**

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Page **200** of **233** tribal leaders. The letters provided information regarding the EPA’s development of NSPS and emission guidelines for EGUs and offered consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. Other tribes participated in the call for information gathering purposes. In this meeting, the EPA provided ba ckground 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 p er 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 Agency (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 w ill 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**02/2 8** **/2012 Draft**

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Page **201** of **233** where it is appropriate. We specifically solicit additional comment
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, 1997) because it is not economically significant 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, helping to pro tect 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. G. 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**02/2 8** **/2012 Draft**

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Page **202** of **233** have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry. H. Executive Order 12898: Federal A ctions 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 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, policie s, and activities on minority populations and low - income populations in the U.S. The EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority or low - income populations, b ecause 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**02/2 8** **/2012 Draft**

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Page **203** of **233** 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 effec ts; these include the poor, the elderly, those already in poor health, the disabled, those living alone, and indigenous populations dependent on one or a few resources. In addition, the U.S. Climate Change Science Program stated as one of its conclusions: ”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 dispropo rtionately impacted by climate change.” These specific sub - populations may receive particularly important benefits from reductions in GHGs . I. 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 Census Standards 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**02/2 8** **/2012 Draft**

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Page **204** of **233** 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 when an a gency 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 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 (Inst rumental 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 NO X Emission Rat es) 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 (H eating) 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**02/2 8** **/2012 Draft**

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Page **205** of **233** 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. Consistent with the NTTAA, the EPA conducted searches to identify VCS in addition to the identified EPA methods. No applicable 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, an d other important technical and policy considerations. 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 thi s action.**02/2 8** **/2012 Draft**

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Page **207** of **233** 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.**02/2 8** **/2012 Draft**

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Page **208** of **233** For the reasons stated in the preamble, 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 for part 60 continues to read as follows: Authority: 42 U.S.C. 7401, et seq . 2. Part 60 is amended by adding subpart TTTT to read as follows: **Subpart TTTT Standards of Performance for Greenhouse Gas Emissions**  **for Electric 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 and Compliance Determination Procedures** §60.5535 How do I monitor and collect data to demonstrate**02/2 8** **/2012 Draft**

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Page **209** of **233** compliance? §60.5540 How do I demonstrate compliance and determine e xcess

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 for 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) (2 50 million British thermal units per hour (MMBtu/h)) heat input of fuel .**02/2 8** **/2012 Draft**

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Page **210** of **233 §60.5510 What is the affected source of this subpart?**  (a) The affected facility to which this 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 mu nicipal 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 subsecti on, a “transitional 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)**02/2 8** **/2012 Draft**

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Page **211** of **233** and (2), and that received a complete permit that meets the 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 greenhou**  **se gases are regulated 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 - hour s (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 , you may comply with each standard in paragraphs (b)(1 ) - (3 ) as an alternative to complying with paragraph (a) of this section. (1) For each year until the first full year of operation of the CCS system, y ou must not discharge any gases that contain CO 2 from the affected EGU into the atmosphere in excess of ___ kg/MWh gross output on a 12 - operating month rolling average basis , and**02/2 8** **/2012 Draft**

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Page **212** of **233** (2) Beginning with the first full year of operation of the CCS system, 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 , and ( 3 ) You must not discharge any gases that contain CO 2 from the affected EGU into the atmosphere in excess of 450 kg/MWh gross o utput 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 imple cycle combustion turbine s 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 emissi ons limits 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 g ood practices for minimizing CO 2**02/2 8** **/2012 Draft**

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Page **213** of **233** emissions. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limited to, fuel use 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 emissions limits in §60.5520, yo u 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 wit hin 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 Exceedance of Emission Limit During Malfunction.**  In response to an action to enforce the standards you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caus ed 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**02/2 8** **/2012 Draft**

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Page **214** of **233** requirements in the affirmative defense. The affirmative defense shall not be available for claim s for injunctive relief. (a) To establish the affirmative defense in any action to 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 preponderanc e 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 b een 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 patter n indicative of inadequate design, operation, or maintenance; (2) Repairs were made as expeditiously as practicable when the applicable emission limitations were being exceeded. Off - shift and overtime labor were used, to the extent practicable to make thes e repairs; (3) The frequency, amount and duration of the excess emissions (including any bypass) were minimized to the maximum extent**02/2 8** **/2012 Draft**

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Page **215** of **233** 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 prevent 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 environment 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, cont emporaneous 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 elimina te 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**02/2 8** **/2012 Draft**

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Page **216** of **233** the Administrator by telephone or facsimile (FAX) transmission as soon as practicable, but no later than tw o (2) business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties 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 op erator 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 o r operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedances.

**Monitoring and Compliance Determination Procedures §60.5535 How do I monitor and collect data to demonstrate compliance?**  (a) You must 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 applicable requirements in §60.13, 40 CFR part 75, and this section. (b) Fo llow the applicable quality assurance procedures for CO 2**02/2 8** **/2012 Draft**

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Page **217** of **233** 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 fuel sampling as allowed 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 t he 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 li** **mit?** (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 hourl y CO 2 mass emissions for each hour of the**02/2 8** **/2012 Draft**

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Page **218** of **233** 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 of the operating month. (3) Sum the hourly CO 2 mass emissions for the opera ting 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 and divide by 12 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 affected 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 pa ragraphs (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 output in terms of MWh for the month.**02/2 8** **/2012 Draft**

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Page **219** of **233** (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 11 operating months to determine the 12 - o perating 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 de termined 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 affecte d 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)**02/2 8** **/2012 Draft**

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Page **220** of **233** 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. (b) You must follow the applicable reporting requirements and submit reports as required in subpart G o f 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 use d 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 fuel 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 -**02/2 8** **/2012 Draft**

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Page **221** of **233** 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 operating month. **§60.5565 In what form and how long must I keep my records?** (a) Your records must be i n a form suitable and readily available for expeditious review. (b) You must keep each record for 5 years following the date of each occurrence, measurement, maintenance, 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 40 years following the date of initial startup of the affected EGU. (c) You must keep each rec ord on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to §60.10. You can keep the records off site for the remaining years as required by this subpart. **Other Requiremen ts and Information**  **§60.5570 What parts of the General Provisions apply to me?**  Table 1 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19 apply to you.**02/2 8** **/2012 Draft**

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Page **222** of **233 §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 the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has th e authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency. (b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the 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 tribal 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 will have**02/2 8** **/2012 Draft**

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Page **223** of **233** the meaning given them in the Clean Air Act and in subpart A (Ge neral Provisions of this part. Affirmative defense means, in the context of an enforcement 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 rating 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 t he 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 th at includes capture and compression of CO 2 produced by an electric utility generating unit before release 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 formation s, oil and gas reservoirs, and unmineable coal seams. Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal**02/2 8** **/2012 Draft**

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Page **224** of **233** ref use, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent - refined coal, gasified coal (not meeting the definition of natural gas), coal - oil mixtures, and coal - water mixtures are included in this definition for the purposes of this subpart. Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and in organic 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 specifications 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 ASTM D975 (incorporated by reference,**02/2 8** **/2012 Draft**

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Page **225** of **233** 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 in ASTM D6751 (incorporated by refere nce, 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 unit or stationary combusti on 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 distr ibution 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 averagi ng 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, requi rements within any applicable State implementation plan, and any permit requirements established under 40**02/2 8** **/2012 Draft**

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Page **226** of **233** CFR 52.21 or under 40 CFR 51.18 and 51.24. Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. Gaseous fuel means any fuel that is present as a gas at standard conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke - oven gas, synthetic gas, and gasified coal. Gross output means 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 mec hanical output or to enhance the performance of the unit ( i.e. , steam delivered to an industrial process). Integrated gasification combined cycle electric utility generating unit means an electric utility combined cycle gas turbine that is designed to bur n 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**02/2 8** **/2012 Draft**

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Page **227** of **233** humidity and 101.3 kilopascals pressure. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), comp osed 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 additi on, natural gas contains 20.0 grains or less of total sulfur 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 g as, 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 minus purchased power on a calen dar 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 elec tric 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**02/2 8** **/2012 Draft**

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Page **2 28**  of **233** error, linearity check, or quality assurance audit that indicates 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 corrective action that demonstr ates that the instrument is measuring and recording within the applicable performance specifications. Potential electric output 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 cap acity would have a 289,080 MWh 12 month potential electrical output capacity). Simple cycle combustion turbine means a stationary combustion turbine that which does not recover heat from the combustion turbine exhaust gases for purposes other than enhancing the performance of the combustion turbine itself. Solid fuel means any fuel t hat has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Stationary combustion turbine means all equipment, including but**02/2 8** **/2012 Draft**

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Page **229** of **233** 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 co ntrol technology, and any ancillary components and sub - components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system. Stationary means that the
c ombustion 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 eithe r the boiler or to power auxiliary equipment. Useful thermal output means the thermal energy made available for use in any industrial or commercial process, or used in any heating or cooling application, i.e., total thermal energy made available for proces ses and applications other than electrical generation or to enhance the performance of the stationary combustion**02/2 8** **/2012 Draft**

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Page **230** of **233** turbine. Thermal output for this subpart means the energy in recovered thermal output measured against the energy in the thermal output at ISO conditions.**02/2 8** **/2012 Draft**

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Page **231** of **233 02/2** **8 /2012 Draft** 

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Page **232** of **233** 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**02/2 8** **/2012 Draft**

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Page **233** of **233** §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