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 carbon dioxide (CO2) for new affected fossil fuel-fired electric utility generating units (EGUs). The EPA is proposing these requirements because CO2 is a greenhouse gas (GHG) and fossil fuel-fired power plants are the country's largest stationary source emitters 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, which are strictly limited to new sources, would require new fossil fuel-fired EGUs greater than 25 megawatt electric (MWe) to meet an output-based standard of 1,000 pounds of CO2 per megawatt-hour (lb CO2/MWh), based on the performance of widely used natural gas combined cycle (NGCC) technology. Because of the economics of the energy sector, the EPA and others project that NGCC will be the predominant choice for new fossil fuel-fired generation even absent this rule. In its base case analysis, the EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal through 2030. New coal-fired or pet coke-fired units could meet the standard either by employing carbon capture and storage (CCS) of approximately 50% of the CO2 in the exhaust gas at startup, or through later application of more effective CCS to meet the standard on average over a 30-year period. The 30-year averaging option could also provide flexibility for owners and operators of coal or pet coke units implementing CCS at the outset of the unit's operation that were designed and operated to emit at less than 1,000 lb CO2/MWh to address startup concerns or short term interruptions in their ability to sequester captured carbon dioxide. The EPA is not proposing standards of performance for existing EGUs whose CO2 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.
DATES: Comments. Comments must be received on or before [INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE]. Under the Paperwork Reduction Act (PRA), since the Office of Management and Budget (OMB) is required to make a decision concerning the information collection request between 30 and 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 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<EMAIL_ADDRESS>Persons wishing to provide testimony should notify Ms. Garrett at least 2 days in advance of the public hearings. The public hearings 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 information on the public hearings, please check the EPA's website for this rulemaking, http://www.epa.gov/airquality/carbonpollutionstandards.
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<EMAIL_ADDRESS>Attn: Docket ID No. EPA-HQ-OAR-2011-0660.
      Facsimile: Fax your comments to<PHONE_NUMBER>, Attn: Docket ID No. EPA-HQ-OAR-2011-0660.
      Mail: Send your comments to the EPA Docket Center, U.S. EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 20460, Attn: Docket ID No. EPA-HQ-OAR-2011-0660. 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, Washington, DC, 20460, Attn: Docket ID No. EPA-HQ-OAR-2011-0660. Such deliveries are accepted only during the Docket's normal hours of operation (8:30 a.m. to 4:20 p.m., Monday through Friday, excluding legal holidays), and special arrangements should be made for deliveries of boxed information.
	Instructions: All submissions must include agency name and docket ID number (EPA-HQ-OAR-2011-0660). The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at http://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404-02), Office of Air Quality Planning and Standards, U.S. EPA, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2011-0660. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD-ROM that you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for 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 that does not contain the information claimed as CBI or otherwise protected should be sent.
	The www.regulations.gov website is an "anonymous access" system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through http://www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses.
	Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not publicly available (e.g., CBI or other information whose disclosure is restricted by statute). Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is<PHONE_NUMBER>, and the telephone number for the Air Docket is<PHONE_NUMBER>. Visit 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 Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg/. The TTN provides information and technology exchange in various areas of air pollution control.
FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number<PHONE_NUMBER>, facsimile number<PHONE_NUMBER>; email address<EMAIL_ADDRESS>or Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number<PHONE_NUMBER>, facsimile number<PHONE_NUMBER>; email address<EMAIL_ADDRESS>SUPPLEMENTARY INFORMATION: Acronyms. A number of acronyms and chemical symbols are used in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference 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 Mechanical Engineers
ASTM			American Society for Testing of Materials
BACT			Best Available Control Technology
BDT			Best Demonstrated Technology
BSER			Best System of Emission Reduction
Btu/kWh		British Thermal Units per Kilowatt Hour
Btu/lb		British Thermal Units per Pound
CAA			Clean Air Act
CAIR			Clean Air Interstate Rule
CBI			Confidential Business Information
CCS	Carbon Capture and Storage (or Sequestration)
CDX	Central Data Exchange
CEDRI	Compliance and Emissions Data Reporting
CEMS			Continuous Emissions Monitoring System
CH4			Methane
CHP			Combined Heat and Power
CO2			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			Enhanced Oil Recovery
EPA			Environmental Protection Agency
FR			Federal Register
GHG			Greenhouse Gas
H2			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
kg/MWh		Kilogram per Megawatt-hour
kJ/kg		Kilojoules per Kilogram
kWh			Kilowatt Hour
lb CO2/MMBtu	Pound of CO2 per Million British Thermal Unit
lb CO2/MWh		Pound of CO2 per Megawatt-hour
lb CO2/yr		Pound of CO2 per Year
lb/lb-mole	Pound per Pound-Mole
MATS			Mercury and Air Toxic Standards
MW			Megawatt
MWe			Megawatt Electric
MWh			Megawatt-hour
N2O			Nitrous Oxide
NAAQS		National Ambient Air Quality Standards
NAICS		North American Industry Classification System
NAS			National Academy of Sciences
NETL			National Energy Technology Laboratory
NGCC			Natural Gas Combined Cycle
NRC			National Research Council
NSPS			New Source Performance Standards
NSR			New Source Review
NTTAA		National Technology Transfer and Advancement Act
O2			Oxygen Gas
OMB			Office of Management and Budget
PC			Pulverized Coal
PFC			Perfluorocarbon
PM			Particulate Matter
PM2.5			Fine Particulate Matter
PRA			Paperwork Reduction Act
PSD			Prevention of Significant Deterioration
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
SCR			Selective Catalytic Reduction
SF6			Sulfur Hexafluoride
SIP			State Implementation Plan
SNCR			Selective Non-Catalytic Reduction
SO2			Sulfur Dioxide
SSM			Startup, Shutdown, and Malfunction
Tg			Teragram
Tpy			Tons per Year
TSD			Technical Support Document
TTN			Technology Transfer Network
UIC			Underground Injection Control
UMRA			Unfunded Mandates Reform Act of 1995
U.S.			United States
USGCRP		U.S. Global Climate Research Program
VCS			Voluntary Consensus Standard
WWW			Worldwide Web

	Organization of This Document. The information presented in this preamble is organized as follows:
I. General Information
A. Executive Summary
B. Does this action apply to me?
II. Background
A. Statutory Background for this Rule
B. Overview of Climate Change Impacts from GHG Emissions
C. GHGs from Fossil Fuel-Fired 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 Standards: New Sources
A. How did the EPA establish the emission limits?
B. How did the EPA determine the other requirements for the proposed standards?
V. Implications for PSD and Title V Programs
A. Overview
B. Implications for PSD Program
C. Implications for Title V Program
VI. Discussion of Modified Sources
A. CAA Section 111 Requirements
B. Timing for Promulgation of Standards of Performance for Modifications
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 Risks
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations

 I. General Information
A. Summary
1. Executive Summary
      In this rulemaking, the EPA proposes to limit GHG emissions from new fossil fuel-fired power plants by limiting CO2 emissions. The proposed rule is undertaken pursuant to section 111 of the Clean Air Act, which establishes a several step process for the EPA and the States to regulate air pollutants from stationary sources. Under section 111, 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 demonstrated."
      In today's action, the EPA is proposing to combine electric utility steam generating units (boilers and IGCC units, which are currently included in the Da category) and combined cycle units that generate electricity for sale and meet certain size criteria (which are currently included in the KKKK category), into a new category for new sources (the TTTT category) for the purposes of GHG emissions. The EPA is proposing standards of performance that require that all new fossil fuel-fired EGUs meet an electricity-output-based emission rate of 1,000 lb CO2/MWh of electricity generated on a gross basis. This proposed standard is based on the demonstrated performance of natural gas combined cycle (NGCC) units, which are currently in wide use throughout the country, and are likely to be the predominant fossil fuel-fired technology for new generation in the future.
      New coal-, coal refuse-, oil- and petroleum coke-fired boilers and IGCC units should also be able to meet this standard by employing carbon capture and storage (CCS) technology. While a coal unit with CCS may be more expensive to construct than NGCC generation, for reasons explained below, we expect the difference to decrease over time as CCS becomes more mature and less expensive.
      We include in today's proposed rulemaking a 30-year averaging compliance option under which affected coal- and pet coke-fired sources could comply with the 1,000 lb CO2/MWh standard on a 30-year average basis. Coal- and pet coke-fired EGUs that use this compliance alternative must meet an immediate performance standard of 1,800 lb CO2/MWh (gross) on a 12-month annual average basis, which can be achieved by a "supercritical" efficiency level, during the period before installation of CCS. By no later than the beginning of the 11[th] year, the facility would be required to meet a reduced CO2 emission limit of no more than 600 lb CO2/MWh (gross) on a 12-month annual average basis for the remaining 20 years of the 30-year period, such that the weighted average CO2 emissions rate from the facility over the 30-year time period would be equivalent to the proposed standard of performance of 1,000 lb CO2/MWh.
      Today's proposal to require an emission rate of 1,000 lb CO2/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 generation. NGCC qualifies as the "best system of emission reduction" (BSER) that the EPA has determined has been adequately demonstrated. New natural gas-fired EGUs are less costly than new coal-fired EGUs, and as a result, our Integrated Planning Model (IPM) model projects that for economic reasons, natural gas-fired EGUs will be the facilities of choice until at least 2020, which is the analysis period for this rulemaking.
      Indeed, our IPM model does not project construction of any new coal-fired EGUs during that period. This state of affairs has come about primarily because technological developments and discoveries of abundant natural gas reserves have caused natural gas prices to decline precipitously in recent years and have secured those relatively low prices for the near-future. We emphasize that, in light of a number of economic factors, including 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.
      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 with construction of new coal-fired capacity. At present, while CCS would add considerably to the costs of a new coal-fired power plant, there are sources of funding available to support the deployment of CCS, including a limited number of government demonstration programs. Even if companies decide to construct a few new coal-fired power plants under any circumstance, those few may well have access to those government programs. We expect that the costs of CCS will decline in the future as CCS matures and is utilized more widely.
      For purposes of today's action, the EPA does not have a sufficient base of information to develop a proposal for the anticipated 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.
      The EPA is aware that approximately 15 proposed EGUs have received CAA permitting authority approval for their preconstruction permits, but may not have "commenced construction" by the date of today's proposed rulemaking. For this proposed rule, these sources 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." In today's proposed rulemaking, the EPA is not proposing a standard of performance for transitional sources, which we define as sources that have been issued a PSD permit by the date of proposal (including sources that have approved permits that are 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 12 months of the date of publication of this proposal in the Federal Register. Upon finalization of this rulemaking without a standard of performance applicable to these sources, they will not be treated as new sources subject to the specific limitations set forth in the final new source standards.
Our IPM modeling, using Energy Information Administration (EIA) reference case assumptions, projects that there will be no construction of new coal-fired generation without CCS by 2030. Under these assumptions, the proposed rule will not impose costs by 2030. We also examined a scenario with both increased future natural gas prices and increased future electric demand. In this sensitivity case, we saw small amounts of coal-fired generation being built in 2030. Even under this sensitivity analysis with small amounts of new coal generation under conditions of high natural gas prices and simultaneously high electricity demand in 2030, we do not project that this proposed rule will impose notable costs upon sources.
We seek comments on all aspects of this proposal and identify a number of aspects of the proposal on which comments are specifically requested.
B. Overview and Outline1. Overview
      In this rulemaking, the EPA proposes to limit GHG emissions from new fossil fuel-fired power plants by limiting CO2 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 fuel-fired power plants emit more GHG emissions than any other stationary source category in the United States, and among new GHG emissions sources, the largest individual sources are in this source category. This rulemaking proposes federal standards of performance for new fossil fuel-fired power plants that can be met with existing technology.
      Note that in this preamble, while we refer to these sources, interchangeably, as power plants, steam generating units, affected sources, fossil fuel-fired electric generating units, covered EGUs, or, simply, EGUs, 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 CO2 and other GHG emissions, 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 CO2 pollution from fossil fuel-fired power plants because they are responsible for approximately 40 percent of all U.S. anthropogenic CO2 emissions. Individual new coal-fired power plants are among the largest individual new sources of GHGs. Furthermore, design and technology choices, such as NGCC, exist that can be readily and cost-effectively used to reduce GHG emissions from new 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 National Academies 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."
	Action to reduce emissions is warranted because, as the EPA stated in its 2009 Endangerment Finding, GHGs endanger the public health and public welfare of current and future generations. The anthropogenic buildup of GHGs in the atmosphere is very likely (90 to 99 percent probability) the cause of most of the observed global warming over the last 50 years. Based on the Endangerment Finding and its underlying technical support document (TSD), 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.
    * 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.
    * Human-induced climate change impacts have the potential to be far-reaching and multidimensional, though not all risks and potential impacts can be quantified.
    * 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 national security issues for the United States.
     The TSD further notes that some risks, such as the extinction of many species, would be irreversible. Also, the TSD points to research on the potential for "abrupt changes" which have uncertain or low probability but high potential impact. The NRC has said abrupt changes are an important consideration because, if triggered, they could occur so quickly and unexpectedly that human or natural systems would have difficulty adapting to them. 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 sheet or collapse of the West Antarctic ice sheet leading to many feet of sea level rise.
	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 greenhouse gas. Greenhouse gases will continue to accumulate in the atmosphere at higher and higher concentrations each year unless substantial reductions in global greenhouse gas emissions are achieved. The NRC notes that emissions reduction choices made today matter in determining the level of impacts experienced not just over the next few decades, but in the coming centuries and millennia. Also, the longer that the U.S. and other countries take to reduce emissions, the greater the future emissions reductions that will be required to limit global temperature increase to any given level.
	This proposed rule to limit 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 approximately 40 percent of total U.S. anthropogenic CO2 emissions, based on 2009 data. Among all stationary sources of GHG emissions, fossil-fuel-fired power plants generally constitute the largest individual sources.
      Furthermore, a range of options are available to reduce emissions of new power plants. For economic reasons, most new power plants being built in the U.S. today are either natural gas-fired or are powered by renewable sources of energy, such as wind and solar, and therefore generally produce significantly fewer CO2 emissions than uncontrolled coal-fired power plants. Natural gas combustion inherently emits less CO2 than coal combustion and the technology of choice for generating electricity with natural gas, stationary combined cycle gas turbines, is also more efficient. Almost all the stationary combined cycle gas turbines built in the U.S. in the last five years can meet the proposed standard of 1,000 lb CO2/MWh. New coal-fired power plants can install CCS technology and can thereby limit their CO2 emissions per MWh generated to levels similar to, or even lower than, those of natural gas-fired combined cycle plants without CCS. New coal-fired power plants with CCS are being permitted and built today, albeit usually with considerable financial assistance from the federal government.
c. Alignment with Industry's Other CAA Obligations. Establishing the overall regulatory requirements for GHG emissions from new fossil fuel-fired power plants at this time is efficient because the EPA has recently issued regulations to limit criteria and hazardous air pollutants from these sources. Aligning the timing of these GHG rules with the rules for criteria and air toxics pollutants gives the industry more regulatory certainty, will facilitate the industry's investment decisions, and will help inform its compliance decisions to meet all of its CAA obligations.
d. Promotion of Energy Diversity. This proposed rule is consistent with the President's goal to ensure that "by 2035 we will generate 80% of our electricity from a diverse set of clean energy sources - including renewable energy sources like wind, solar, biomass and hydropower, nuclear power, efficient natural gas and clean coal." The proposed rule will assist the deployment of CCS technology for new coal-fired power plants and reinforce incentives for the use of efficient natural gas-fired generation. Regulatory uncertainty may be hindering the development and deployment of CCS, as evidenced by American Electric Power (AEP)'s recent deferral of a large-scale CCS retrofit demonstration project on one of its coal-fired power plants because the State's utility regulators would not approve CCS without a regulatory requirement to reduce CO2. The standard established in this proposal would help create the regulatory certainty that CCS is the path forward for new coal-fired generation.
3. Legal Proceedings Leading up to this Rulemaking
      In April 2007, the U.S. Supreme Court ruled, in Massachusetts v. EPA, 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 remand 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 criteria 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 fossil fuel-fired EGUs.
4. Legal Basis for CAA Standards for Fossil-Fired 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 categories of stationary sources that cause or contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. Then, the EPA must regulate emissions from new sources in the source category by issuing a standard of performance, which is defined as "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account ... cost [and other factors]) ... has been adequately demonstrated." New sources include new construction, and, as discussed below, modifications to existing sources as well as reconstructed sources. Standards of performance for new sources are often referred to as new source performance standards (NSPS).
b. Cause-or-Contribute-Significantly Finding for Fossil Fuel-Fired Power Plants and Endangerment Finding for GHG Air Pollution. The EPA is authorized to regulate GHGs from power plants based on earlier actions concerning endangerment. Before today's rulemaking, the EPA listed different types of fossil fuel-fired EGUs as source categories that caused or contributed significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. Specifically, the EPA listed electric utility steam generating boilers, including coal-fired boilers, and initially regulated them in subpart D of its regulations under CAA section 111. Subsequent regulation of utility boilers has been under subpart Da. The EPA listed stationary combustion turbine engines and initially regulated them under subpart GG. The stationary combustion turbine engine portions of combined cycle facilities were also regulated under subpart GG. Heat recovery steam generators (HRSG) associated with combined cycle facilities with duct burners were regulated under either subpart Da or one of the industrial boiler regulations, depending on the specific characteristics of the HRSG. To minimize the compliance burden for owners/operators of combined cycle facilities some monitoring harmonization was done, but the two subparts were still applicable. In 2005, the EPA proposed subpart KKKK as a replacement for subpart GG and specifically covered the entire combined cycle facility under subpart KKKK such that only a single set of 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 rulemaking proposed today -- which would establish standards of performance for CO2 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 is considering whether CAA section 111 should be interpreted to require that the EPA base its regulation of CO2 emissions from EGUs on two findings: (i) a finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare; and (ii) a finding that CO2 emissions from EGUs cause or contribute significantly to that air pollution. If section 111 were so interpreted, the EPA believes that (a) the 2009 Endangerment Finding, along with the EPA's 2010 action denying 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 CO2 emissions from EGUs clearly exceeds the low applicability threshold upon which the EPA would make the cause-or-contribute-significantly finding.
      As another alternative, the EPA is also considering whether CAA section 111 should be interpreted to require that the EPA base its regulation of CO2 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 CO2, provide a rational basis for regulating CO2 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.
5. Summary of Today's Proposed Requirements 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 proposing to combine electric utility steam generating units (boilers and IGCC units, which are currently included in the Da category) and combined cycle units that generate electricity for sale and meet certain size criteria (which are currently included in the KKKK category), into a new category for new sources (the TTTT category) for the purposes of GHG emissions. Today's proposed rulemaking would not affect NSPS requirements for criteria air pollutants, simple cycle turbines or EGUs located in non-continental areas. It also would not affect biomass-fired boilers (including those that sell electricity to the grid) that co-fire with less than 250 MMBtu/h of any fossil fuel (biomass boilers currently subject to subpart Db, the Industrial-Commercial-Institutional Steam Generating Unit NSPS).
ii. Control Requirements for New Sources. The EPA is proposing standards of performance that require that all new fossil fuel-fired EGUs meet an electricity-output-based emission rate of 1,000 lb CO2/MWh of electricity generated on a gross basis. This proposed standard is based on the demonstrated performance of natural gas combined cycle (NGCC) units, which are currently in wide use throughout the country, and are likely to be the predominant fossil fuel-fired technology for new generation in the future.
      New coal-, coal refuse-, oil- and petroleum coke-fired boilers and IGCC units should also be able to meet this standard by employing CCS technology. There are currently a number of coal- and pet coke-fired EGU projects under development that include CCS. While a coal unit with CCS may be more expensive to construct than NGCC generation, for reasons explained below, we expect the difference to decrease over time as CCS becomes more mature and less expensive.
      We include in today's proposed rulemaking a 30-year averaging compliance option under which affected coal- and pet coke-fired sources could comply with the 1,000 lb CO2/MWh standard on a 30-year average basis. Coal- and pet coke-fired EGUs that use this compliance alternative must meet an immediate performance standard of 1,800 lb CO2/MWh (gross) on a 12-month annual average basis, which can be achieved by a "supercritical" efficiency level, during the period before installation of CCS. By no later than the beginning of the 11[th] year, the facility would be required to meet a reduced CO2 emission limit of no more than 600 lb CO2/MWh (gross) on a 12-month annual average basis for the remaining 20 years of the 30-year period, such that the weighted average CO2 emissions rate from the facility over the 30-year time period would be equivalent to the proposed standard of performance of 1,000 lb CO2/MWh.
      We seek comment on this compliance option and on reasonable variations on the framework we propose to establish, and in particular on a mechanism for establishing practicably enforceable short term limits during the 30-year period. The potential approaches here include (1) requiring the owner/operator to identify and obtain approval of, at the time of construction, an alternative 30-year emission trajectory to the 10- and 20-year limits described immediately above; and (2) specifying the emission rate for each year during the 30-year period consistent with meeting a 30-year average emission rate of 1,000 lb CO2/MWh. Such an option would provide coal-fired sources that intend to use a reduction technology, such as CCS, significant flexibility in how that reduction technology is implemented. They could install the technology as part of the original project but use some or all of the initial ten year period to optimize the system. Such flexibility could be particularly useful to early adopters (i.e., "first movers") of the technology. Alternatively, they could delay installation of the technology for a period of up to ten years to take advantage of advancements in the technology that could reduce costs and enhance performance. 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. As proposed, this 30-year averaging compliance option is available only to new coal- and pet coke-fired EGUs. We do not believe that it is necessary for NGCC units, as they should be able to meet the proposed performance with no need for add-on technology. We also solicit comment on the need to extend the applicability for the 30-year averaging compliance option to other fossil fuels beyond just coal and pet coke.
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 the relevant parts of the categories is reasonable because with the combination, all new fossil fuel-fired electricity generating units that meet specified minimum criteria will be subject to the same requirements, and therefore will be treated alike because they serve the same function, that is to serve baseload or intermediate demand. The EPA is not including stationary simple cycle turbines in this rule because they generally operate differently than the other units covered by today's rule. The units covered by today's rule are generally used to serve baseload or intermediate demand, while simple cycle turbines are generally used much less often (and thus have lower GHG emissions) and are generally used to meet peak demand rather than base or intermediate load requirements.
      Today's proposal does not apply to new sources in non-continental areas, which include Hawaii and the territories. This is because non-continental areas do not have available pipeline quality natural gas and, accordingly, a natural-gas-fired plant that could comply with the 1,000 lb CO2/MWh may not be feasible. At present, we do not have information to identify what types of new power plants may be constructed in those areas. Those types of power plants may range from liquified natural gas (LNG)-, to oil-, to coal-fired to renewables. Our lack of more specific information precludes us from proposing, at this time, a standard for new sources in non-continental areas.
	Today's proposal to require an emission rate of 1,000 lb CO2/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 generation. NGCC qualifies as the "best system of emission reduction" (BSER) that the EPA has determined has been adequately demonstrated because NGCC emits the least amount of CO2 and does so at the least cost. 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 CO2 emissions that the 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 Integrated Planning Model (IPM) model projects that for economic reasons, natural gas-fired EGUs will be the facilities of choice until at least 2020, which is the analysis period for this rulemaking. Indeed, our IPM model does not project construction of any new coal-fired EGUs during that period. This state of affairs has come about primarily because technological developments and discoveries of abundant natural gas reserves have caused natural gas prices to decline precipitously in recent years and have secured those relatively low prices for the near-future. Importantly, because the IPM modeling shows that natural gas-fired plants are the facilities of choice, the proposed standard of performance in today's rulemaking  -  -  which is based on the emission rate of a new NGCC unit  -  -  does not add costs. In addition, compared to coal-fired EGUs, natural gas-fired EGUs have fewer nonair quality health and environmental impacts. This is true under not only a set of base-case assumptions, but also under a sensitivity considering significantly higher gas prices.
	The just-described reasons are sufficient as a legal matter to justify today's proposed actions to combine source categories and establish the 1,000 lb CO2/MWh standard. Such a standard could also be met today by new coal-fired units using CCS. In addition, we propose to include the compliance alternative of allowing new coal- and pet coke-fired power plants to meet the 1,000 lb CO2/MWh standard over a 30-year period so that plant developers can take advantage of future advancements cost savings in CCS technology that could lower its cost. This compliance alternative allows owners/operators to install CCS when the unit is first constructed but also provides the operational flexibility that may be necessary to optimize the performance and to have additional time to address any startup challenges related to issues such as business arrangements related to the sale or storage of the captured CO2.
      We recognize that, in light of a number of economic factors, including 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. For these economic reasons, and independent of this proposed standard, the fossil fuel-fired electricity generating industry has been trending towards increased use of natural gas and decreased use of coal for new generating capacity. Today's proposed action is consistent with that trend; but, at the same time, today's proposal is not intended to affect that apparent 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 with construction of new coal-fired capacity. In the first instance, a new coal-fired power plant may be able to meet the 1,000 lb CO2/MWh standard by installing CCS at the time of construction. At present, while CCS would add considerably to the costs of a new coal-fired power plant, there are sources of funding available to support the deployment of CCS, including a limited number of government demonstration programs. Even if companies decide to construct a few new coal-fired power plants under any circumstance, those few may well have access to those government programs.
      The proposed 30-year averaging compliance option adds additional flexibility for new coal- and pet coke-fired power plants by allowing them to construct and begin operations without CCS, and then to install and operate CCS at some time in the future, as long as they install CCS within ten years and operate it in a manner that allows them to meet the 1,000 lb CO2/MWh standard, on a weighted average basis, over the 30-year period.
      We expect that the costs of CCS will decline in the future as CCS matures and is utilized more widely. Today's action, if finalized, would promote utilization and further development of CCS by making it clear that CCS would be necessary for new coal-fired power plants to meet the performance standard. The prospect of declining CCS costs, in conjunction with the possibility of continued availability of additional funding mechanisms (e.g. demonstration funding such as Department of Energy (DOE) grants, tax credits (for investment and/or EOR), State incentives such as clean energy standards), and sale of other usable products such as CO2, sulfur and hydrogen based products, indicates that CCS may well be sufficiently accessible in the near term to the few coal-fired power plants that are expected to commence construction. Thus, the 30-year averaging compliance option, along with the potential opportunities for funding to implement CCS immediately, helps to alleviate 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 averaging compliance option on grounds that it qualifies as the "best system of emission reduction" adequately demonstrated, and we are not stating in this action 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 averaging compliance option, along with the opportunity to implement CCS to meet the 1,000 lb CO2/MWh standard immediately upon startup, make CCS an available option for the limited number of new coal-fired power plants that may construct to serve the policy goals of promoting energy diversity, as well as other policy objectives. Indeed, by clarifying that, in the future, new coal-fired power plants will need to implement CCS, this rulemaking eliminates uncertainty about the status of new coal and may well enhance the prospects for new coal-fired generation.
      In addition, there may also be other potential compliance options available that were not considered in this proposal. In the analysis for today's proposal, the EPA did not include unique treatment of CO2 emissions from biologically-based material, otherwise called biogenic CO2 emissions.
      In 2011, the EPA prepared and submitted the draft Accounting Framework for Biogenic CO2 Emissions from Stationary Sources (http://www.epa.gov/climatechange/emissions/biogenic_emissions/study.html). The draft Framework includes both a detailed examination of the scientific and technical issues related to accounting for biogenic CO2 emissions from stationary sources, and a proposed method to account for a stationary source's onsite CO2 emissions, taking the biological cycling of carbon into consideration, in a scientifically and technically rigorous manner. The independent Science Advisory Board (SAB) has convened a Biogenic Carbon Emissions Panel (http://yosemite.epa.gov/sab/sabproduct.nsf/0/2F9B572C712AC52E8525783100704886?OpenDocument) to conduct a peer review of the draft Framework. The peer review report will be finalized later in 2012.
      The SAB's peer review of the EPA's discussion on the science related to the impacts of biogenic CO2 is not yet finalized and the EPA looks forward to the SAB's conclusions later in 2012. Given that the SAB's peer review is ongoing, the EPA is not suggesting specific methods of accounting or otherwise making particular proposals for treatment of biogenic CO2 emissions in any stationary source program, including NSPS. As more information, including the SAB peer review, becomes available, the EPA will consider its options and move forward as warranted.
c. Requirements and Rationale for NSPS Modifications for GHGs. For purposes of today's action, the EPA does not have a sufficient base of information to develop a proposal for the affected sources that may be expected to take actions that would constitute "modifications" (as defined under the EPA's NSPS regulations) for GHGs and therefore be subject to requirements for new sources. As a result, the EPA is not proposing requirements for NSPS modifications for GHGs.
      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 projects that entail the installation of pollution control equipment or systems. Based on current information, most of the projects that we believe EGUs are most likely to undertake in the foreseeable future that could increase the maximum achievable hourly rate of CO2 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 criteria and air toxics air pollutants. These increases in CO2 emissions 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 111(d) rulemaking for existing sources and would have the effect of increasing a source's maximum achievable hourly emission rate (lb CO2/hr), even while decreasing its actual output based emission rate (lb CO2/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.
      Our base of knowledge concerning NSPS modifications has depended largely on the enforcement actions brought against power plants and on self-reporting by power plants.  Over the lengthy history of the NSPS program, those have been too few in number to allow us to develop a sufficiently robust base of knowledge to propose a standard of performance for NSPS modifications for GHGs at this time.
      In addition, the sources that took these actions vary widely one from another, and the types of actions were disparate. In light of this, as noted, we do not have adequate information as to the types of actions that qualify as modifications, the amount of increase in CO2 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. We note that the statute contemplates that in circumstances such as these (where section 111(d) is implicated), sources not subject to the new source standards would be treated as existing sources subject to section 111(d).
      In today's action, we solicit comment on the types of modifications power plants may undertake and the 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 15 proposed EGUs have received CAA permitting authority approval for their preconstruction permits, but may not have "commenced construction" by the date of today's proposed rulemaking.
     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 approximately six of these sources have plans 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 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. These commenters have suggested that today's proposed rule should treat transitional sources differently,  especially in light of the substantial redesign that meeting such the proposed standard would have and the impact that redesign would have on the schedule for a project that was nearly ready to commence construction. The transitional sources at issue are coal-fired EGUs that, absent special treatment, 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 have been issued a PSD permit by the date of proposal (including sources that have approved permits that are 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 12 months of the date of publication of this proposal in the Federal Register. Upon finalization of this rulemaking without a standard of performance applicable to these sources, they will not be treated as new sources 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 that 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 this standard of performance for new sources.
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 and, therefore, subject to new source standards of performance. The regulations define reconstructed sources as, in general, existing sources (i) that replace components to such an extent that the capital costs of the new components exceed 50 percent 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.
      As with NSPS modifications, our base of knowledge concerning reconstructions has depended largely on the enforcement actions brought against power plants and on self-reporting by power plants.  Over the lengthy history of the NSPS program, those have been too few in number to allow us to develop a sufficiently robust base of knowledge to propose a standard of performance for reconstructions for GHGs at this time. Thus, 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 emissions reductions, that we need to propose a standard of performance for reconstructions.
	 As a result, in today's action, the EPA is not including a proposal for reconstructed units for GHGs. Instead, we solicit comment on how we should approach reconstructions and, depending on the information we receive, we may propose and finalize a standard for reconstructions at a later time.
6. Summary of Emissions Impacts, Costs and Benefits
     Our IPM modeling, using Energy Information Administration (EIA) reference case assumptions, projects that there will be no construction of new coal-fired generation without CCS. In addition we examined a case with higher future electric demand and another case with higher future natural gas prices. We did not see any additional new construction of coal-fired generation through 2030 in either of these cases. Under the relevant assumptions, we do not project that this rule will impose notable costs.
We also examined a scenario with both increased future natural gas prices and increased future electric demand. In this sensitivity case we saw small amounts of coal-fired generation being built in 2030. Even under this sensitivity analysis with small amounts of new coal generation under conditions of high natural gas prices and simultaneously high electricity demand in 2030, we do not project that this proposed rule will impose notable costs upon sources. (See the RIA for further discussion of sensitivities).
While this proposed rule also will not have direct impact on U.S. emissions of greenhouse gases under expected economic conditions, it provides assurance that emission rates from new fossil fuel-fired generation will not exceed the level of the standard and will send a strong signal both domestically and internationally. Domestically, this proposed rule can further stimulate investment in CCS and other clean coal technologies, by making it clear that such technologies do provide a clear path forward for new coal-fired generating capacity. Internationally, this rule may encourage others to consider less GHG-intensive forms of power generation.
B. Does this action apply to me?
      The entities potentially affected by the proposed standards are shown in Table 1 below.
                   Table 1. Potentially Affected 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 Government
                                    921150
        Fossil fuel electric power generating units in Indian Country.

[a] Include NAICS categories for source categories that own and operate electric power generating units (including boilers and stationary combined cycle combustion turbines).
 [b] Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged.

       This table is not intended to be exhaustive but rather to provide a guide for readers regarding entities likely to be affected by this proposed action. To determine whether your facility, company, business, organization, etc., would be regulated by this proposed action, you should examine the applicability criteria in 40 CFR 60.1. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
II. Background
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."
     Once it has listed a source category, the EPA establishes "standards of performance" that apply to new sources, which are sources that are constructed, or that undertake modifications or reconstruction, after the EPA proposes the standards of performance for the relevant source category. CAA section 111(b)(1)(B). Specific statutory and regulatory 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 air 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 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 degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.

We call this level of control the best system of emission reduction (BSER). The standard that the EPA develops, based on the BSER, is commonly a numerical emissions limit, expressed as a performance level (e.g., a rate-based standard). Generally, the EPA does not prescribe a particular technological system that must be used to comply with a standard of performance. Rather, sources remain free to elect whatever combination of measures will achieve equivalent or greater control of emissions.
B. Overview of Climate Change Impacts from GHG Emissions
     In 2009, the EPA Administrator issued the 2009 Endangerment Finding, under CAA section 202(a)(1), as part of the process for promulgating the Light Duty Vehicle Rule. With the Endangerment Finding, the Administrator found that elevated concentrations of GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare. 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). In brief, these assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change problem, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review and acceptance. Below is a brief, non-comprehensive summary of effects noted in the Endangerment Finding and the assessment reports.
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 vulnerable 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 surface ozone levels. Ozone health studies indicate that elevated surface ozone increases risks of premature death, acute bronchitis, heart attacks, asthma aggravation, and other respiratory effects.
     Public health threats also stem from increases in intensity or frequency of extreme weather associated with climate change, such as increased hurricane intensity, increased frequency of intense storms and heavy precipitation. The assessment literature indicates that there is the potential for hurricanes 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 mental 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
     Climate 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 face increased risks from storm and flooding damage to property, as well as adverse impacts from sea level rise such as land loss due to inundation, erosion, wetland submergence, and habitat loss.
     Climate change is expected to result in an increase in peak electricity demand, and changes in extreme weather threaten energy, transportation, and water resource infrastructure. Climate changes may exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities. Over the 21[st] century, climate change will fundamentally rearrange U.S. ecosystems.
     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 surface ozone, 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 increasing risks of net adverse impacts on U.S. food production, agriculture, and forest productivity as temperatures continue to rise, with the potential for significant disruptions and crop failure.
     Human-induced climate change has the potential to be far-reaching and multidimensional. Given the long atmospheric lifetime of the six GHGs, which range from roughly a decade to centuries, future atmospheric greenhouse gas concentrations for the remainder of this century and beyond will be influenced not only by future emissions but indeed by 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 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 National Academy of Sciences (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). It concluded that "climate change is occurring, is caused largely by human activities, and poses significant risks for -- and in many cases is already affecting -- a broad range of human and natural systems." 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 (IPCC) Fourth Assessment Report, and other assessments of the state of scientific knowledge on climate change." 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 are crossed, such as the release of large quantities of GHGs stored in frozen soils in the Arctic or irreversible drying and desertification in the subtropics; and of potential for broad, "catastrophic" impacts on marine ecosystems resulting from ocean acidification.
     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 CO2 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 extent, 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 century, that for an increase of 1 to 2 ºC the area burnt by wildfires 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 Fossil Fuel-Fired Power Plants
     Fossil fuel-fired electric utility generating units are by far the largest emitters of GHGs, primarily in the form of CO2, among stationary sources in the U.S. This section describes the amount of those emissions and places that amount in the context of the national inventory of GHGs.
     The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks (the U.S. GHG Inventory) to comply with existing commitments under the United Nations Framework Convention on Climate Change. This inventory, which includes recent trends, is presented by industrial sectors. It is the source for the information provided in Table 2 below concerning total U.S. anthropogenic emissions and sinks of GHGs and CO2 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 CO2 Eq.))

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

     Energy-related CO2 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  - - accounted for 40 percent of all energy-related CO2 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 CO2 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 CO2 emissions in 2009. Total CO2 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 CO2 Eq.)

GHG EMISSIONS
                                     1990
                                     2000
                                     2009
Total CO2 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 CH4 - stationary combustion
                                                                           0.6
                                                                           0.7
                                                                           0.7
Total N2O - stationary combustion
                                                                           8.1
                                                                          10.0
                                                                           9.0

      We are aware that nitrous oxide (N2O) (and to a lesser extent, methane (CH4)) may be emitted from fossil fuel-fired EGUs, especially from coal-fired circulating fluidized bed (CFB) combustors and from units with selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) systems installed for NOX control. We are not proposing separate N2O or CH4 emission limits or an equivalent CO2 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 N2O and CH4 from fossil fuel-fired EGUs (9.0 and 0.7 Tg of CO2 equivalent, respectively) is about 0.4 percent of total CO2 equivalent emissions from fossil fuel-fired electric power generating units. We are requesting comment on this approach and on the need to collect additional data on N2O and CH4 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 criteria pollutant emissions of EGUs included in the Da category. "Standards of Performance for Electric Utility Steam Generating Units, Industrial-Commercial-Institutional Steam Generating Units, and Small Industrial-Commercial-Institutional Steam Generating Units," 71 FR 9866 (Feb. 27, 2006) (the "2006 Final Rule"). The 2006 Final Rule did not establish standards of performance for GHG emissions. Two groups of petitioners filed petitions for judicial review of this rule in the U.S. Court of Appeals for the District of Columbia Circuit (the Court), contending, among other things, that the rule was required to include standards of performance for GHG emissions from EGUs. The two groups of petitioners were (1) the 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 (NRDC), Sierra Club, and Environmental Defense Fund (EDF)(collectively ``Environmental Petitioners'').
	The portions of State and Environmental Petitioners' petitions for review of the 2006 Final Rule that related to GHG emissions were severed from other petitions for review of that rule, and were formally pending before the Court under the caption State of New York, et al. v. EPA, No. 06 - 1322. Following the U.S. Supreme Court's decision in Massachusetts, discussed above, the Court, upon motion from the EPA, remanded the 2006 Final Rule for further consideration of the issues related to GHG emissions in light of 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 includes standards of performance for GHGs for new and modified EGUs that are subject to 40 CFR part 60, subpart Da; and (2) a rule under CAA section 111(d) that includes emission guidelines for GHGs from existing EGUs that would have been subject to 40 CFR part 60, subpart Da if they were new sources. Pursuant to CAA section 113(g), the EPA published a notice of the proposed settlement agreement in the Federal Register, and provided for a public comment period. 75 FR 82392 (December 30, 2010). The EPA considered the comments received and concluded that they did not disclose facts or considerations indicating that the proposed settlement agreement was inappropriate, improper, inadequate or inconsistent with the CAA. Therefore, the EPA concluded that the proposed settlement agreement should be finalized.
E. Coordination with Other Rulemakings
	EGUs are the subject of several CAA rulemakings that have been recently completed. The EPA recognizes that it is important that all of these efforts achieve their intended environmental objectives in a common sense manner. The confluence of these rulemakings allows the industry to look across the regulatory requirements and design cost effective integrated compliance strategies.
      On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). 76 FR 48208 (August 8, 2011). Also known as the Transport Rule, the CSAPR requires a total of 28 states and the District of Columbia to improve air quality by reducing power plant emissions that contribute to ozone and fine particle pollution in other States. The CSAPR applies to 3,642 EGUs at 1,081 coal-, gas- and oil-fired facilities in the eastern half of the U.S. By 2014, combined with other final state and EPA actions, the CSAPR will reduce power plant SO2 emissions by 73 percent and NOX emissions by 54 percent from 2005 levels in the CSAPR region. The CSAPR was scheduled to begin on January 1, 2012. However, on December 30, 2011, the U.S. Court of Appeals for the D.C. Circuit issued a ruling to stay the rule pending judicial review. This decision is not a ruling on the merits of the CSAPR. While this decision delays implementation of the CSAPR and the significant health benefits associated with the rule, it leaves the Clean Air Interstate Rule (CAIR), the predecessor regulation to CSAPR, in place while the Court considers the merits of the challenges to the CSAPR. Oral arguments are scheduled for April 13, 2012.
      On December 16, 2011, the EPA signed 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 requires investments in pollution controls to reduce emissions of mercury, other metals and acid gases by 2015 or 2016. In the same notice, the EPA also revised the NSPS for criteria pollutants from these sources. Because the control technologies and strategies that reduce SO2 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 structures existing at power plants and factories. 76 FR 22174 (April 20, 2011). These facilities pull in large volumes of cooling water from lakes, rivers, estuaries or oceans to cool their machinery. The EPA is currently considering a wide range of comments to this proposal.
      The EPA recognizes that it is important that each of these efforts achieves its intended environmental objectives in a common-sense, cost effective manner, that is consistent with the underlying statutory requirements and 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 identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation.'' Recent guidance from the Office of Information and Regulatory Affairs has emphasized the importance of, where appropriate and feasible, considering cumulative effects and of seeking to harmonize rules in terms of both content and timing.
      Thus, the EPA recognizes that it needs to approach these rulemakings, to the extent that its legal obligations permit, in ways that allow the industry to make 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 proposing today has implications for EGUs and other stationary sources under the prevention of significant deterioration (PSD) and Title V programs. We discuss this issue in section VI, below, and we include relevant background information in 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 organizations, 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 their expertise in the CAA standard-setting process. The EPA had asked key stakeholder groups to identify these round table participants in advance of the listening sessions. The EPA accepted comments from the public at the end of each session and via the electronic docket system.
   From the listening sessions and written submissions, the EPA received a wide range of comments and ideas for this proposed rule. The main topics of the comments, which concerned requirements for both new and existing sources, included the following:
   * Feasibility and availability 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 states 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
   * Consideration 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 provided in Section IV of this preamble.
A. What is the affected source?
Sources affected by today's proposal for new source provisions are sources that are 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 and more than 25 MW net-electrical output (MWe) to any utility power distribution system for sale, with certain exceptions noted below. For this proposed rule, covered EGUs include electric utility steam generating units ("boilers"), stationary combined cycle combustion turbines and their associated 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 stationary simple cycle combustion turbines or EGUs located in Hawaii or other non-continental areas. In addition, units subject to emission requirements under CAA section 129 would not be subject to requirements under this proposed rule.
2. CO2 Emissions Only
      This action proposes to regulate covered EGU emissions of CO2, and not other constituent gases of the air pollutant GHG, although we identify the pollutant we propose to regulate as GHGs. Note that emissions of criteria pollutants for covered 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 such source." In contrast, CAA section 111(a)(6) defines an "existing source" as "any stationary source other than a new source." The definition of a "new source" applies according to its terms for purposes of this rulemaking, except that special considerations come into play for sources undertaking physical or operational changes, transitional sources, and sources undertaking reconstruction, as discussed below in Section V of this preamble.
B. What emissions limitations must I meet?
      In this rulemaking, the EPA is proposing a standard of performance (NSPS), and we are requesting comment on an 30-year averaging compliance option, for CO2 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 CO2 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 CO2 emission limit that must be met by all affected sources. Specifically, the EPA is proposing a standard of 1,000 lb CO2/MWh, but, as discussed below, is taking comment on a range from 950 lb CO2/MWh to 1,100 lb CO2/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 combined heat and power (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. 30-year Averaging Compliance Option
      We also propose a 30-year averaging compliance option that would be available only for affected coal- and pet coke-fired sources that comply with the standard through the use of CCS. This approach involves a performance standard that includes both a 12-month annual 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 source 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 instance, if meeting the 30-year limit was predicated on installing CCS 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. Note that after the 30[th] year, the source would be required to meet the 12-month annual average 1,000 lb CO2/MWh emission limit.
      Specifically, for the first ten years of operation, the affected source would be required to comply with a 12-month annual average CO2 emissions limit based on the best demonstrated performance of a coal-fired facility without CCS, which is 1,800 lb CO2/MWh (816 kg CO2/MWh) (gross). This proposed emission limit can be met by modern coal-fired facilities using supercritical steam conditions, IGCC facilities, and pressurized CFBs boilers. By no later than the 11[th] year from the effective date of the rule, the facility would be required to meet a reduced emission limit of no more than 600 lb CO2/MWh (272 kg CO2/MWh) (gross) on a 12-month annual average basis for the remaining 20 years of the 30-year averaging period, such that the weighted average CO2 emissions rate from the facility over the 30-year time period would be equivalent to the proposed standard of performance of 1,000 lb CO2/MWh. This reduced emissions standard during the remainder of the 30-year period would be met with some level of CCS.
      For added flexibility, under this option, we are taking comment on allowing the owner/operator to select a different emission trajectory to achieving the 30-year average as long as the owner/operator obtains EPA approval of that rate before beginning operations. Such a trajectory would have to assure that, assuming similar amounts of operation in each year, the overall overage emission rate would be at or below the required 30-year average of 1,000 lb CO2/MWh. For instance, if an owner or operator wished to operate at a rate of 2,000 lb CO2/MWh for the first period, it would have to commit to something more stringent than achieving a 600 lb CO2/MWh standard by the 11[th] year. Potential compliance pathways could include committing to a limit of 500 lb CO2/MWh by the 11[th] year or committing to a limit of 600 lb CO2/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 operators did not intend to install CCS when the unit commenced operation, they could be required to submit a plan that includes a location to store CO2 and a schedule for construction and operation of their carbon capture system. The schedule would include key milestone dates such as soliciting proposals, obtaining financing, beginning 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 the 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. We 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 30-year averaging compliance option may be warranted for at least two 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 number of DOE-funded demonstration projects. A new coal- or pet coke-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 CO2/MWh standard on a 30-year basis. A second reason that this alternative 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 those related to the capture technology or the arrangements for sequestration). For instance, a company's ability to sequester CO2 may be dependent upon construction by a third party of a pipeline that will be transporting the CO2 to a site to be used for enhanced oil recovery or permanent sequestration. Because the owner or operator does not have direct control over this 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-fired unit capable of capture, it will have to remain non-operational for a period of time until the pipeline project or sequestration destination is completed. The 30-year averaging 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 1,000 lb CO2/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 of the complexity of integration of the technologies and the fact that the business model is new for the power sector. Because the policy purpose of this 30-year averaging 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 CO2/MWh level.
      We note that under CAA section 111(b)(1)(B), "the Administrator shall, at least every 8 years, review and, if appropriate, revise [the] standards [of performance] ... ". This review is required to take place in 2020, if not sooner. In the event that the EPA adopts the 30-year averaging compliance option, then at the time of the next required review, the EPA will evaluate the state of development or commercialization of CCS technologies and make a determination as to whether or not the 30-year averaging approach is 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 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 30-year averaging compliance option should automatically 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 CO2 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 startup 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 30-year averaging compliance option.
      This 30-year averaging compliance option is available only  to new coal- and pet coke-fired EGUs. We do not believe that it is necessary for NGCC units, as they should be able to meet the proposed performance with no need for add-on technology. We also solicit comment on the need to extend the applicability for the 30-year averaging compliance option to other fossil fuels beyond just coal and pet coke. We seek comment on all other aspects of this 30-year averaging compliance option.
C. What are the startup, shutdown, and malfunction requirements?
1. Startups and Shutdowns
      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 CO2 standard, we accounted for periods of startup and shutdown by considering periods of part-load operation. As noted above, the proposed method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the electrical energy output and useful thermal energy output, where applicable for CHP EUGs, over a rolling 12-month period. This averaging approach gives more weight to high-load hours and more accurately reflects overall environmental performance. In addition, because low-load hours do not factor as heavily into the calculated average, the impact of including periods of startup and shutdown is minimized when calculating emission rates.
      We solicit comment on the alternative of requiring compliance through an annual (calendar year) average.
      We propose that these same requirements for startups and shutdowns would apply to the 30-year averaging compliance option.
2. Malfunctions
      The 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 malfunction events in setting emission standards. See, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (DC Cir. 1978) (``In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by `uncontrollable acts of third parties,' such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation.")
      Further, it is reasonable to interpret CAA section 111 as not requiring the EPA to account for malfunctions in setting emissions standards. For example, we note that section 111 provides that the EPA set standards of performance which reflect the degree of emission limitation achievable through ``the application of the best system of emission reduction'' that the EPA determines is adequately demonstrated. Applying the concept of ``the application of the best system of emission reduction'' to periods during which a source is malfunctioning presents difficulties. The ``application of the best system of emission reduction'' is more appropriately understood to include operating units in such a way as to avoid malfunctions.
Further, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not "reasonably" 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 conduct the perfect study."). In addition, the goal of a best controlled or best performing source is to operate in such a way as to avoid malfunctions of the source and accounting for malfunctions could lead to standards that are significantly less stringent than levels that are achieved by a well-performing non-malfunctioning source. The EPA's approach to malfunctions is consistent with section 111 and is a reasonable interpretation of the statute.
      In the event that a source fails to comply with the applicable CAA section 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 ascertain 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 careless 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 emission standard. (See, e.g., "State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown" (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983), which are both included in the docket for this rulemaking.) The EPA is therefore proposing to add to the final rule an affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions. See 40 CFR 60.10042 (defining "affirmative 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 judicial 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 elements 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, infrequent, 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 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...." 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 limitations were being exceeded..." and that "[a]ll possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health...." In any judicial or administrative proceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met its burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with section 113 of the CAA (see also 40 CFR part 22.77).
      The EPA is including 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 concentration of emissions of air pollutants on a continuous basis." 42 U.S.C. §7602(k)(defining "emission limitation and emission standard"). See generally Sierra Club v. EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008) Thus, the EPA is required to ensure that section 112 emissions limitations are continuous. The affirmative defense for malfunction events meets this requirement by ensuring that even where there is a malfunction, the emission limitation is still enforceable through injunctive relief. While "continuous" limitations, on the one hand, are required, there is also case law indicating that in many situations it is appropriate for the EPA to account for the practical realities of technology. For example, in Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that in setting standards under CAA section 111 "variant provisions" such as provisions allowing for upsets during startup, shutdown and equipment malfunction "appear necessary to preserve the reasonableness of the standards as a whole and that the record does not support the `never to be exceeded' standard currently in force." See also, Portland Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973). Though intervening case law such as Sierra Club v. EPA and the CAA 1977 amendments undermine the relevance of these cases today, they support the EPA's view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil penalties for excess emissions that are proven to be beyond the control of the source. By incorporating an affirmative defense, the EPA has formalized its approach to upset events. In a Clean Water Act setting, the Ninth Circuit required this type of formalized approach when regulating "upsets beyond the control of the permit holder." Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9[th] Cir. 1977). But see, Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal approach is adequate). The affirmative defense provisions give the EPA the flexibility to both ensure that its emission limitations are "continuous" as required by 42 U.S.C. §7602(k), and account for unplanned upsets and 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 compliance option; however, we take comment on whether it is appropriate to have an affirmative defense for the 30-year averaging portion of that compliance option, given that we would expect malfunctions to only impact shorter emissions limits, and the longer the compliance period, the less likely malfunction events are to impact a source's ability to meet the standard.
D. What are the continuous monitoring requirements?
      The EPA is proposing that a CO2 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 other 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 malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments); failure to collect required data is a deviation of the monitoring requirements.
     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 requirements would apply to the 30-year averaging 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 performance test to demonstrate compliance with the CO2 emissions limits beginning in the calendar month following initial certification of the CO2 and flow rate monitoring CEMS.
     We propose that the initial performance test consist of collection of hourly CO2 average concentration, mass flow rate (standard cubic feet per hour) recorded with the certified CO2 concentration and flow rate CEMS and the corresponding electrical power generation data for all of the hours of operation for the first calendar year beginning on the first day of the first month following completion of the CEMS installation and certification. For all of the operating hours during each monthly period, including startup and shutdown, you would calculate compliance with the emissions limit by dividing the sum of the hourly CO2 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 averaging compliance option.
F. What are the continuous compliance requirements?
In this rulemaking, we propose that compliance with the applicable average CO2 mass emissions rate (lb/MWh) must be calculated as a 12-month rolling average, updated monthly, using the reported hourly CO2 average concentration and flow rate values from the certified CEMS data collected for the previous month's process operating days along with generation data tracked by the facility for the unit. We propose that compliance with the emissions limit must be calculated by dividing the sum of the hourly CO2 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 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) average emission limit, which would be calculated through comparable methodology as just described.
      We propose that these same continuous compliance requirements would apply to the 30-year averaging compliance option.
G. What are the notification, recordkeeping, and reporting requirements?
In this rulemaking, the EPA is proposing that you, as the owner or operator of a new unit, must comply with the notification and recordkeeping requirements in the section 111 regulatory general provisions, 40 CFR part 60, subpart A, and need to report results of performance testing and excess emissions; as well as record and maintain hourly average CO2 emissions concentration, hourly average flow rate, and hourly useful electrical generation. Note that the summary form identified as Figure 1 in 40 CFR part 60.7(d) will be revised to include CO2 as a pollutant. We are also seeking comments on whether the EPA should require initial notification of compliance status reports. In most rules, an initial notification of compliance status report, where owners and operators of sources subject to a particular rule notify the EPA and State and Local Air Pollution Control Agencies that their source is subject to the rule and how they intend to comply with the rule, is required. Regulators find this information very helpful in implementing and enforcing particular rules. In this case, most, if not all, of the sources that are potentially subject to this rule have already been identified because they are subject to other New Source Performance Standards and Part 75 Acid Rain provisions.
      As part of an Agency-wide effort to facilitate reporting of environmental data and reports, we are requiring electronic reporting of selected reports, required by this regulation, to the EPA. We are proposing that owners and operators subject to this regulation must electronically submit excess emissions, continuous monitoring systems performance and-or summary reports required under section 60.7(c). Owners and operators would need to submit these reports to the EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed in the Central Data Exchange (CDX). The CDX is the EPA's portal for submitting and managing electronic environmental data and reports and is accessed at www.epa.gov/cdx. The CDX is needed to meet the EPA standards for electronic reporting set by the Cross-Media Electronic Reporting Rule. For more information, please see http://www.epa.gov/cromerr/. Owners and operators required to submit electronic reports would need to register to use the CDX and for the CEDRI node at http://cdx.epa.gov/epa_home.asp. Once a user has access to CDX and CEDRI, the owners and operators would use the subpart specific forms in CEDRI to enter the information for the 60.7(c) required reports.
In most New Source Performance Standards owners and operators are required to keep records of their reports on site for at least 2 years. Since the owner or operator would be submitting the data in these reports to be housed in CDX and WebFIRE, we are proposing to forgo recordkeeping requirements for those reports required to be submitted in proposed section 60.5555(a)(1). We believe that since the WebFIRE database is public that the need for recordkeeping onsite for certain information will not be needed as the information will be readily available for all stakeholders to access.
We are aware that owners or operators of many existing EGUs are required to submit some emissions data through the EPA Acid Rain Program's Emissions Collection and Monitoring Plan System (ECMPS) for SO2, NOx, CO2, and other related data. We propose for affected sources to continue to use ECMPS with modifications to allow for collecting CO2 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 modification of the ECMPS system to collect, track, and calculate CO2 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 operators 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.