Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units

Federal RegisterApr 13, 2012

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2011-0660; FRL-9654-7]

RIN 2060-AQ91

Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

The United States EPA is proposing new source performance standards for emissions of carbon dioxide (CO

) for new affected fossil fuel-fired electric utility generating units (EGUs). The EPA is proposing these requirements because CO

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 CO

per megawatt-hour (lb CO

/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 CO

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 CO

/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 CO

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.

Throughout this preamble, we refer to `carbon capture and storage' or CCS. By this, we mean the use of a technology for separating and capturing CO

from the flue gas or syngas stream with subsequent compression and transportation to a suitable location for long term storage and monitoring. Many references refer to CCS as `carbon capture and sequestration'. In this preamble, `storage' and `sequestration' mean the same thing and the words are used interchangeably.

DATES:

Comments.

Comments must be received on or before June 12, 2012. 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 April 13, 2012, a comment to the OMB is best assured of having its full effect if the OMB receives it by May 14, 2012.

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:

garrett.pamela@epa.gov.

Persons wishing to provide testimony should notify Ms. Garrett at least 2 days in advance of the public hearings. The public 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 Web site 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 Web site http://www.regulations.gov:

Follow the instructions for submitting comments.

At the Web site http://www.epa.gov/oar/docket.html:

Follow the instructions for submitting comments on the EPA Air and Radiation Docket web site.

Email:

Send your comments by electronic mail (email) to

a-and-r-docket@epa.gov,

Attn: Docket ID No. EPA-HQ-OAR-2011-0660.

Facsimile:

Fax your comments to (202) 566-9744, Attn: Docket ID No. EPA-HQ-OAR-2011-0660.

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 17th 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 email. 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

Web site 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 (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. Visit the EPA Docket Center homepage at

http://www.epa.gov/epahome/dockets.htm

for additional information about the EPA's public docket.

In addition to being available in the docket, an electronic copy of this proposed rule will also be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:

http://www.epa.gov/ttn/oarpg/.

The TTN provides information and technology exchange in various areas of air pollution control.

FOR FURTHER INFORMATION CONTACT:

Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-4003, facsimile number (919) 541-5450; email address:

fellner.christian@epa.gov

or Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-2968, facsimile number (919) 541-5450; email address:

hutson.nick@epa.gov.

SUPPLEMENTARY INFORMATION:

Acronyms.

A number of acronyms 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

Methane

CHP Combined Heat and Power

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

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 CO

/MMBtu Pound of CO

per Million British Thermal Unit

lb CO

/MWh Pound of CO

per Megawatt-hour

lb CO

/yr Pound of CO

per Year

lb/lb-mole Pound per Pound-Mole

MATS Mercury and Air Toxic Standards

MW Megawatt

MWe Megawatt Electric

MWh Megawatt-hour

O 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

Oxygen Gas

OMB Office of Management and Budget

PC Pulverized Coal

PFC Perfluorocarbon

PM Particulate Matter

2.5

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

Sulfur Hexafluoride

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction

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 CO

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 CO

/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 CO

/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 CO

/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 11th year, the facility would be required to meet a reduced CO

emission limit of no more than 600 lb CO

/MWh (gross) on a 12-month annual average basis for the remaining 20 years of the 30-year period, such that the weighted average CO

emissions rate from the facility over the 30-year time period would be equivalent to the proposed standard of performance of 1,000 lb CO

/MWh.

Today's proposal to require an emission rate of 1,000 lb CO

/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

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 Outline

1. Overview

In this rulemaking, the EPA proposes to limit GHG emissions from new fossil fuel-fired power plants by limiting CO

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 CO

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 CO

pollution from fossil fuel-fired power plants because they are responsible for approximately 40 percent of all U.S. anthropogenic CO

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.

Or 32.4% of all anthropogenic GHG emissions; from information in Table 2-1 from `Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009,' U.S. Environmental Protection Agency, EPA 430-R-11-005, April 2011.

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.”

The National Academies comprise the National Academy of Sciences, National Academy of Engineering, Institute of Medicine and National Research Council.

National Research Council (2011)

America's Climate Choices,

Committee on America's Climate Choices, Board on Atmospheric Sciences and Climate, Division on Earth and Life Studies, The National Academies Press, Washington, DC.

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:

EPA, “Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act” (74 FR 66,496; Dec. 15, 2009).

http://epa.gov/climatechange/endangerment.html.

Endangerment Finding at 74 FR 66,518, which notes that the 2007 conclusion of the Intergovernmental Panel on Climate Change was re-confirmed by the June 2009 assessment by the U.S. Global Change Research Program.

EPA, “Technical Support Document for Endangerment and Cause or Contribute Findings for

Greenhouse Gases under Section 202(a) of the Clean Air Act, Dec. 9, 2009.” Both the

Federal Register

Notice and the TSD for Endangerment and Cause or Contribute Findings are found in the public docket established for the endangerment rulemaking, Docket No. EPA-OAR-2009-0171 and at

http://epa.gov/climatechange/endangerment.html.

• 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.

Endangerment Finding, 74 FR 66498.

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

Endangerment Finding, 74 66497.

• 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.

Endangerment Finding, 74 FR 66535.

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.

Endangerment TSD, p. 136.

Endangerment TSD, p. 75-78. The U.S. Climate Change Science Program defined “abrupt change” as a “large-scale change in the climate system that takes place over a few decades or less, persists (or is anticipated to persist) for at least a few decades, and causes substantial disruptions in human and natural systems.” Synthesis and Assessment Product (SAP) 3.4: Abrupt Climate Change (2008).

Endangerment TSD, p. 75, citing National Research Council (2002).

Endangerment TSD, pp. 76-78.

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.

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

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 CO

emissions, based on 2009 data.

Among all stationary sources of GHG emissions, fossil-fuel-fired power plants generally constitute the largest individual sources.

Or 32.4% of all anthropogenic GHG emissions; from information in Table 2-1 from `Inventory of U. S. Greenhouse Gas Emissions and Sinks: 1990—2009', U. S. Environmental Protection Agency, EPA 430-R-11-005, April 2011.

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 CO

emissions than uncontrolled coal-fired power plants. Natural gas combustion inherently emits less CO

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 CO

/MWh. New coal-fired power plants can install CCS technology and can thereby limit their CO

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 CO

The standard established in this proposal would help create the regulatory certainty that CCS is the path forward for new coal-fired generation.

“Blueprint for a Secure Energy Future”, March 30, 2011.

In a July 17, 2011, press release, AEP's chairman said, “We are placing the project on hold until economic and policy conditions create a viable path forward * * * We are clearly in a classic `which comes first?' situation. The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry's share.”

3. Legal Proceedings Leading up to This Rulemaking

In April 2007, the U.S. Supreme Court ruled, in

Massachusetts

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.

549 U.S. 497 (2007).

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 CO

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 CO

emissions from EGUs on two findings: (i) A finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare; and (ii) a finding that CO

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 CO

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 CO

emissions from EGUs on a rational basis for protection of the public health or welfare. If section 111 were so interpreted, the EPA believes that (i) its 2009 Endangerment Finding and 2010 denial of petitions to reconsider, by themselves, and particularly in conjunction with the National Academy of Sciences' assessment reports issued since then, coupled with (ii) the fact that EGUs are the largest stationary source emitters of CO

, provide a rational basis for regulating CO

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.

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

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).

Thus, today's rulemaking does not affect the Da and KKKK categories for conventional pollutants and does not affect the KKKK category for simple cycle turbines.

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 CO

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 CO

/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 CO

emission limit of no more than 600 lb CO

/MWh (gross) on a 12-month annual average basis for the remaining 20 years of the 30-year period, such that the weighted average CO

emissions rate from the facility over the 30-year time period would be equivalent to the proposed standard of performance of 1,000 lb CO

/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 CO

/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.

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 CO

/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 CO

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 CO

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 CO

/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 CO

/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 CO

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.

/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.

A number of the sources that EPA has identified as transitional sources have received some form of DOE financial assistance to demonstrate CCS. In addition, several additional projects have received funding but have not yet received air permits. Beyond these projects, prospects for additional federal funding are dependent on the overall budget process.

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 CO

/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 CO

, 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 CO

/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.

EIA analysis (AEO 2012 early release) shows that “coal remains the dominant energy source for electricity 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 CO

emissions from biologically-based material, otherwise called biogenic CO

emissions.

Biologically-based material is defined as non-fossilized and biodegradable organic material originating from modern or contemporaneously grown plants, animals or micro-organisms (including products, by-products, residues and waste from agriculture, forestry and related industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic material).

In 2011, the EPA prepared and submitted the draft Accounting Framework for Biogenic CO

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 CO

emissions from stationary sources, and a proposed method to account for a stationary source's onsite CO

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 CO

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 CO

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.

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.

Note that any analysis of the cost and feasibility of CCS that EPA has undertaken for purposes of this proposal has focused solely on new sources. In today's action, EPA has not undertaken any analysis of the cost or feasibility of CCS for existing units that undergo modifications.

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 CO

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 CO

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 CO

/hr), even while decreasing its actual output based emission rate (lb CO

/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 CO

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.

Requirements for Transitional sources.

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.

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

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.

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

Category

NAICS Code

Examples of potentially regulated entities

Industry

221112

Fossil fuel electric power generating units.

Federal Government

221112

Fossil fuel electric power generating units owned by the federal government.

State/Local Government

221112

Fossil fuel electric power generating units owned by municipalities.

Tribal Government

921150

Fossil fuel electric power generating units in Indian Country.

Include NAICS categories for source categories that own and operate electric power generating units (including boilers and stationary combined cycle combustion turbines).

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.”

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

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.

This level of control has historically been referred to as best demonstrated technology (BDT).

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.

“Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act.” 74 FR 66496 (December 15, 2009).

“Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule.” 75 FR 25324 (May 7, 2010).

74 FR 66510-66511.

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 21st 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.

Carbon dioxide (CO

), nitrous oxide (N

O), methane (CH

), perflurocarbons (PFCs), hydrofluorocarbons (HFCs), and sulfur hexafluoride (SF

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.

NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC.

NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. Page 3.

NRC (2010). Advancing the Science of Climate Change. National Academy Press. Washington, DC. Page 286.

Another NRC assessment, “Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millenia”, was published in 2011 (the 2011 NRC Assessment). This report found that climate change due to CO

emissions will persist for many centuries. The report also estimates a number of specific climate change impacts, finding that every degree Celsius (°C) of warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic sea ice extent, along with other precipitation and stream flow changes. The assessment also found that with an increase of 4 °C, the average summer would be as warm as the warmest summers of the past century, that for an increase of 1 to 2 °C 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 °C 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 CO

, 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 CO

emissions, by industrial sector—including fossil fuel-fired EGUs—for the years 1990, 2000, and 2009.

“Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009”, Report EPA 430-R-11-005, United States Environmental Protection Agency, April 15, 2011.

From Table 2-3 of the EPA GHG Emissions and Sinks Inventory, EPA 430-R-11-005.

Table 2—U.S. GHG Emissions and Sinks by Sector

[Teragram Carbon Dioxide Equivalent (Tg CO

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 CO

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 CO

emissions. The transportation sector, with emissions principally from the combustion of gasoline, diesel, and jet fuel, was the second-largest source, at 32 percent of the total. Other energy-related CO

emission sources included industrial, residential, and commercial fossil fuel combustion, natural gas and petroleum systems, and incineration of waste.

Direct fuel use in the residential and commercial sectors accounted for 26 percent of total CO

emissions in 2009. Total CO

emissions from fossil fuel-fired EGUs, for years 1990, 2000 and 2009, are shown below in Table 3.

Table 3—U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels

[Tg CO

Eq.]

GHG Emissions

1990

2000

2009

Total CO

from fossil fuel combustion

1,820.8

2,296.9

2,154.0

—from coal

1,547.6

1,927.4

1,747.6

—from natural gas

175.3

280.8

373.1

—from petroleum

97.5

88.4

32.9

From use of limestone and dolomite

2.6

2.5

3.8

Total CH

—stationary combustion

0.6

0.7

Total N

O—stationary combustion

8.1

10.0

9.0

We are aware that nitrous oxide (N

O) (and to a lesser extent, methane (CH

)) 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 NO

control. We are not proposing separate N

O or CH

emission limits or an equivalent CO

emission limit in today's action because of a lack of available data for these affected sources. Additional information on the quantity and significance of emissions and on the availability of cost-effective controls would be needed before proposing standards for these pollutants. The estimated emissions for N

O and CH

from fossil fuel-fired EGUs (9.0 and 0.7 Tg of CO

equivalent, respectively) is about 0.4 percent of total CO

equivalent emissions from fossil fuel-fired electric power generating units. We are requesting comment on this approach and on the need to collect additional data on N

O and CH

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.

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.

Copies of the

Federal Register

notice, the settlement agreement, other supporting documents and the comments received are available online at fdms.gov under docket EPA-HQ-2010-1057.

E. 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.

We include this discussion of other rulemakings for background purposes. The effort to coordinate rulemakings does not provide a defense to a violation to the CAA. Sources cannot defer compliance with existing requirements because of other upcoming regulations.

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 SO

emissions by 73 percent and NO

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 DC 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 15, 2011, EPA finalized a supplemental rule (76 FR 80760, December 27, 2012) to include five additional states in the CSAPR ozone season NO

program. On February 7, 2012, EPA issued two sets of minor adjustments to the CSAPR (77 FR 10324, February 21, 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 SO

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. CO

Emissions Only

This action proposes to regulate covered EGU emissions of CO

, 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 a 30-year averaging compliance option, for CO

emissions from affected sources, which are new fossil fired EGUs described above in Section III.A.

1. Standard of Performance

The standard of performance is a gross output-based CO

emission limit expressed in units of emissions mass per unit of useful recovered energy (specifically, in pounds per megawatt-hour (lb/MWh)). This emission limit would be effective upon the effective date of the final action.

We are not proposing any subcategories for new affected sources. Instead, we are proposing a single output-based CO

emission limit that must be met by all affected sources.

Specifically, the EPA is proposing a standard of 1,000 lb CO

/MWh, but, as discussed below, is taking comment on a range from 950 lb CO

/MWh to 1,100 lb CO

/MWh.

As discussed below, we are not proposing such a limit for modifications, transitional sources, or reconstructed sources.

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) EGUs, 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 30th year, the source would be required to meet the 12-month annual average 1,000 lb CO

/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 CO

emissions limit based on the best demonstrated performance of a coal-fired facility without CCS, which is 1,800 lb CO

/MWh (816 kg CO

/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 11th 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 CO

/MWh (272 kg CO

/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 CO

emissions rate from the facility over the 30-year time period would be equivalent to the proposed standard of performance of 1,000 lb CO

/MWh. This reduced emissions standard during the remainder of the 30-year period would be met with some level of CCS.

As discussed elsewhere, EPA is soliciting comment on whether the emissions standard that reflects CCS should be somewhat higher or lower than 1,000 lb CO

/MWh, and whether the emissions standard that reflects supercritical efficiency should be somewhat higher or lower than 1,800 lb CO

/MWh. If EPA does promulgate a higher or lower standard in either case, then EPA may revise the 600 lb CO

/MWh amount accordingly.

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 CO

/MWh. For instance, if an owner or operator wished to operate at a rate of 2,000 lb CO

/MWh for the first period, it would have to commit to something more stringent than achieving a 600 lb CO

/MWh standard by the 11th year. Potential compliance pathways could include committing to a limit of 500 lb CO

/MWh by the 11th year or committing to a limit of 600 lb CO

/MWh by the 8th 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 CO

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 CO

/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 CO

may be dependent upon construction by a third party of a pipeline that will be transporting the CO

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 CO

/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 CO

/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 CO

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 CO

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 EGUs, 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

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

EPA,

167 F.3d 658, 662 (DC 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

EPA,

551 F.3d 1019, 1021 (DC 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

Ruckelshaus,

486 F.2d 427, 433 (DC Cir. 1973), the DC 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

Ruckelshaus,

486 F.2d 375 (DC Cir. 1973). Though intervening case law such as

Sierra Club

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.

EPA,

564 F.2d 1253, 1272-73 (9th Cir. 1977). But

see, Weyerhaeuser Co.

Costle,

590 F.2d 1011, 1057-58 (DC 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.

Note that the Ninth Circuit recently upheld EPA's decision to apply this affirmative defense approach to only actions seeking civil penalties, and not also to actions seeking injunctive relief.

Montana Sulfur & Chemical Co.

EPA, No. 02-71657 (9th Cir. August 31, 2011) (slip op. at 456).

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 CO

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 CO

emissions limits beginning in the calendar month following initial certification of the CO

and flow rate monitoring CEMS.

We propose that the initial performance test consist of collection of hourly CO

average concentration, mass flow rate (standard cubic feet per hour) recorded with the certified CO

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 CO

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 CO

mass emissions rate (lb/MWh) must be calculated as a 12-month rolling average, updated monthly, using the reported hourly CO

average concentration and flow rate values from the certified CEMS data collected for the previous month's process operating days along with generation data tracked by the facility for the unit. We propose that compliance with the emissions limit must be calculated by dividing the sum of the hourly CO

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 CO

emissions concentration, hourly average flow rate, and hourly useful electrical generation. Note that the summary form identified as Figure 1 in 40 CFR part 60.7(d) will be revised to include CO

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 SO

, NO

, CO

, and other related data. We propose for affected sources to continue to use ECMPS with modifications to allow for collecting CO

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 CO

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.

The EPA proposes that these same notice, recordkeeping, and reporting requirements would apply to the 30-year averaging compliance option. The EPA requests comment on whether any alterations or additions are appropriate for the notice, recordkeeping, and reporting requirements that would apply to the 30-year averaging compliance option. The EPA also requests comment on whether sources that utilize the 30-year averaging compliance option should include, as applicable requirements in their title V permits, a specific explanation of their compliance plan, including when CCS would be deployed, what capture rate(s) would be achieved, how the CO

would be sequestered, and whether the company anticipates receiving government financial assistance or other incentives for the CCS.

IV. Rationale for the Proposed Standards for New Sources

A. How did the EPA establish the emission limits?

1. Rationale for Proposing to Combine the Subpart Da Category and a Component of the Subpart KKKK Category into a New Category for Purposes of Regulating GHG Emissions

The EPA is proposing to create a new subpart in 40 CFR part 60 by combining the sources in subpart Da (the Da category) and a subset of the sources in subpart KKKK (the KKKK category)—stationary combined cycle units, but not stationary simple cycle units—for purposes of promulgating standards of performance for emissions of GHGs from new sources. This new subpart will be numbered TTTT. Consistent with standard practice and Executive Order 13563, and in particular its emphasis on “the open exchange of information and perspectives” and “providing an opportunity for public comment on all pertinent parts of the rulemaking docket, including relevant scientific and technical findings” and on consideration of alternatives, we invite comments on our decision to combine the two source categories.

At this time, the EPA is not proposing to subcategorize new sources and is not proposing to combine the Da category and components of the KKKK category for purposes of regulating criteria pollutants.

CAA section 111 provides legal authority for combining the categories into a new category. Clean Air Act section 111(b)(1)(A) provides:

The Administrator shall, within 90 days after December 31, 1970, publish

(and from time to time thereafter shall revise)

a list of categories of stationary sources. He shall include a category of sources in such a list if in his judgment it causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.

(Emphasis added.)

As quoted, this provision grants to the Administrator the authority to “revise” the list of categories. Combining categories, in whole or in part, is a form of “revis[ing]” the list of categories (along with taking other actions, such as adding more categories or delisting categories), and accordingly is authorized.

For three principal reasons, it is appropriate for the EPA to combine the Da category and the stationary combined cycle component of the KKKK category at this time for purposes of regulating GHGs. First, all of the plants covered by the new combined category (including fossil fuel-fired boilers, IGCC units and NGCC units) perform the same essential function, which is to provide generation to serve baseload or intermediate load demand. It is sensible to treat as part of the same category units that generate baseload or intermediate load electricity, regardless of their design or fossil fuel type.

Second, all newly constructed sources have options in selecting their design (although it is true that natural gas-fired plants are inherently lower emitting with regard to CO

than coal-fired plants. As a result, prospective owners and operators of new sources could readily comply with the proposed emission standards by choosing to construct a NGCC unit. These two factors provide sufficient legal rationale for the EPA to combine the Da category and the combined cycle component of the KKKK category for purposes of

establishing a standard of performance for GHG emissions.

The agency has previously combined one type of baseload and intermediate load combined cycle unit (IGCC, previously covered under Subpart GG) with Da units for the purposes of setting a standard [40 CFR 60.41Da(b), Feb. 28, 2005]. This action now similarly combines another type of baseload and intermediate load combined cycle unit (NGCC, previously covered under Subpart KKKK) with Subpart Da units for the purposes of setting a standard.

A third factor lends additional support. Combining the categories does not raise adverse policy concerns. On the basis of comments made during the listening sessions, we anticipate that some commenters may question whether combining the categories and applying the NGCC standard to all new plants within the combined category may limit construction of new coal-fired power plants, and thereby have a disruptive effect on the electric power industry, increase electricity prices and/or have adverse implications for energy diversity in new generation. We do not believe that this action would have those effects. As discussed below, and importantly, economic models forecast no new construction of coal-fired generation without CCS through the analysis period, which extends until 2020 (when the standard will be revisited). Accordingly, economic conditions are expected to be the main driver precluding, or at least limiting, construction of coal-fired EGUs. Because of those economic conditions, there is a strong independent movement of power plants serving baseload generation toward NGCC. In light of that movement, it is appropriate for the EPA to focus on this technology in developing the standard, rather than subcategorizing and providing a separate standard for new coal units.

See Portland Cement Ass'n

EPA,

665 F.3d 177, 190 (D.C. Cir. 2011) (affirming the EPA's decision not to subcategorize in part because of “the universal movement in the portland cement industry towards adoption of preheater/precalciner technology”).

Notwithstanding these points, we recognize the possibility that a limited amount of new coal-fired construction may nevertheless occur. Today's action would not foreclose construction of new coal-fired EGUs. Rather, the new coal-fired EGUs that may be expected to be built in the foreseeable future (and for reasons stated above, this is anticipated to be a relatively small number) may install CCS control equipment (if not at the time of construction, then not long thereafter). By doing so, they may achieve the same average CO

emission rate (at least over time) as a natural gas-fired combined cycle unit. It is reasonable to expect that some coal-fired power plants may be able to implement CCS at the present time, and thereby achieve the 1,000 lb CO

/MWh standard immediately. As noted elsewhere, CCS has been demonstrated to be technologically achievable, and, even though it is costly, there are some State and Federal programs that can make CCS more affordable. Several power companies have announced plans to incorporate CCS at six already permitted coal-fired EGU construction projects in this country (as we discuss below in section V.B., concerning transitional sources). Programs exist that provide some funding for CCS through pilot or other demonstration programs, and we expect those to continue. In addition, we reasonably expect the costs of CCS to decline over time. As discussed below, we are not proposing that CCS does or does not qualify as the “best system of emission reduction” that “has been adequately demonstrated” for new coal-fired power plants. Rather, the feasibility of CCS and its availability for the limited amount of new coal-fired construction that may be expected, means that this action to combine the categories and establish the NSPS at the proposed 1,000 lb CO

/MWh emission limit will not have notable adverse effects on new coal-fired construction or, therefore, on the electric utility industry, electricity prices, or energy diversity. We welcome public comments on this discussion.

On the other hand, at this time, we do not consider it appropriate to include simple cycle facilities as an affected source in the new 40 CFR part 60, subpart TTTT for GHG emissions from new facilities. The reason for this is that the function of a new simple cycle power plant is different than that of a new combined cycle plant or coal-fired plant. Combined cycle plants and coal-fired plants are typically designed to provide baseload or intermediate-load power, while simple cycle turbines are designed to provide peaking power. Because combined cycle power plants and coal-fired power plants both serve the same purpose and have design options to emit CO

at similar levels, we believe it is appropriate to combine them. Because peaking turbines operate less and because it would be much more expensive to lower their emission profile to that of a combined cycle power plant or a coal-fired plant with CCS, the EPA does not believe it is appropriate to include them in this source category.

As noted above, some commenters in the listening sessions did suggest that the EPA not combine the two source categories. The EPA has rejected that option for all the reasons outlined above: (1) Fossil-fuel-fired boilers, combined cycle natural gas units, and IGCC units all serve the same basic function, generating baseload or intermediate load power; (2) the proposed standards can be met by different types of units in the category (NGCC units or coal-fired units with CCS); and (3) it is consistent with industry trends (as further explained elsewhere in this notice: Due largely to current and projected gas and coal price trends, new fossil-fuel-fired builds are projected to be natural gas combined cycle units or coal-fired units with CCS supported by federal funding). There is an additional reason for rejecting the option of retaining (and establishing separate standards for) separate source categories. The EPA's analysis (in Section 5.10 of the RIA) suggests that over a wide range of market conditions, constructing a new unit that meets a limit of 1,000 lb CO

/MWh instead of an advanced coal-fired unit without CCS would likely produce net social benefits. For all of these reasons, retaining separate source categories would be unlikely to generate substantial private cost savings, but at the same time, would create the risk of significantly higher GHG emissions and other air pollutants from some new units, resulting, in turn, in higher social costs.

By the same token, at this time, we do not consider it appropriate to combine the Da category and the combined cycle component of the KKKK category for any pollutants other than GHGs, that is, for criteria pollutants. This is because although coal-fired EGUs have an array of control options for criteria and air toxic air pollutants to choose from, those controls generally do not reduce their criteria and air toxic emissions to the level of conventional emissions from natural gas-fired EGUs.

2. Endangerment and Cause-or-Contribute-Significantly Finding

Overview.

In today's rulemaking, we propose or solicit comment on alternative interpretations for whether section 111 includes prerequisites to rulemaking that involve an endangerment finding and a cause-or-contribute-significantly finding. By its terms, CAA section 111 provides that once the EPA lists a source category for regulation because the category causes or contributes significantly to air pollution that may reasonably be anticipated to endanger public health or

welfare, the EPA then establishes requirements for new sources in that source category. The EPA proposes to interpret these provisions so that it is authorized to promulgate the rulemaking proposed today because it has already determined that both the Da and KKKK source categories cause or contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. The EPA solicits comment on interpreting CAA section 111 in the alternative so as to require (i) an endangerment finding for air pollution not specifically covered by the endangerment finding the EPA made when listing the source category, but that in this case, the EPA's 2009 Endangerment Finding for GHGs under Section 202(a) of the CAA (along with the EPA's 2010 denial of petitions to reconsider (2010 Reconsideration Denial)), fulfills that requirement; and (ii) a cause-or-contribute-significantly finding for air pollutants not specifically covered by the cause-or-contribute-significantly finding the EPA made when listing the source category, and that in this case, the large amounts of CO

emissions from power plants provide a compelling basis allowing the EPA to propose that finding. The EPA also solicits comment on another alternative, which is interpreting CAA section 111 so as not to require a specific endangerment finding or cause or contribute finding, but simply to require the EPA to establish a rational basis for regulating an air pollutant from a source category. In this case, the EPA's 2009 Endangerment Finding for GHGs and the 2010 denial of petitions to reconsider the Endangerment Finding, as well as the large amounts of CO

emissions from power plants, provide that rational basis. Finally, as an alternative for the basis for a rational basis determination, the 2010 and 2011 Assessment Reports from the National Academies confirm the Endangerment Finding and the denial of petitions to reconsider.

Proposal:

Previous Source Category Findings Meet Any Endangerment Prerequisite to Regulation. In this rulemaking, the EPA proposes to interpret CAA section 111 so that we are not required, as a prerequisite to regulating CO

emissions from EGUs, to issue a new finding as to the health or welfare impacts of GHG air pollution or a finding as to the extent that affected sources contribute to that air pollution.

Clean Air Act section 111(b)(1)(A), by its terms, requires that the Administrator list a source category for regulation if the “category * * * in [the Administrator's] judgment, * * * causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.” Clean Air Act section 111(b)(1)(B) goes on to provide that after listing the source category, the EPA must promulgate regulations “establishing federal standards of performance for new sources within such category.” In turn, CAA section 111(a)(1) defines a “standard of performance” as a “standard for emissions of air pollutants which reflects the degree of emission reduction which (taking into account * * * cost * * * and any nonair quality health and environmental impact and energy requirements) * * * has been adequately demonstrated.”

Thus, although CAA section 111 clearly requires the EPA to list a source category if its emissions contribute significantly to air pollution that endangers public health or welfare, and then to promulgate standards of performance for particular pollutants, section 111 does not by its terms require that the EPA make any endangerment finding with respect to those particular pollutants, or any cause-or-contribute-significantly finding with respect to the source category, at the time the EPA promulgates the standards of performance for those pollutants. The lack of any such requirement contrasts with (i) the definition of “standard of performance,” which specifically requires the EPA to consider “

nonair

quality health and environmental impact,” CAA section 111(a)(1) (emphasis added); and (ii) other CAA provisions that do require the EPA to make endangerment and cause-or-contribute findings for the particular pollutant that the EPA regulates under those provisions.

E.g.,

CAA sections 202(a)(1), 211(c)(1), 231(a)(2)(A).

Accordingly, under our proposal, once the EPA has listed a source category, and the EPA proceeds to regulate particular pollutants from that source category, CAA section 111 does not require that the EPA make an endangerment finding for the relevant air pollution or a cause-or-contribute-significantly finding for the relevant air pollutants from that source category. The fact that the EPA is, in this rulemaking, proposing to partially combine the Da and KKKK source categories does not alter this outcome. As noted above, under CAA section 111(b)(1)(A), the EPA may add a source category to the list of categories only after determining that the source category “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” The EPA has previously determined that each of the Da and KKKK categories causes or contributes significantly to such air pollution. Combining the Da category and some of the sources in the KKKK category does not necessitate that the EPA make a new cause-or-contribute-significantly finding for the expanded Da category. This is because the EPA has already found that at least one component of the new category—the former Da sources—by itself causes or contributes significantly to such air pollution. There is no reason why this expansion of the Da category to include the pre-existing Da sources plus additional sources could be considered to contribute to such air pollution to an extent that is less than the contribution from the pre-existing Da sources alone. As a result, the new category must necessarily be considered to cause or contribute significantly to such air pollution.

In addition to proposing this interpretation, we also solicit comment on alternative interpretations under CAA section 111, including those described next.

First Alternative Interpretation:

Endangerment Finding Prerequisite. We solicit comment on an alternative interpretation under which the EPA is required, as a prerequisite to promulgating standards of performance under CAA section 111(b), to have issued an endangerment finding specifically for the relevant air pollution and a cause-or-contribute-significantly finding specifically for the relevant source category and air pollutant. In particular, what would be the legal basis for such an interpretation?

Even if CAA section 111 is interpreted to require those findings, then, in a case in which the EPA did not make those findings under CAA section 111, it is the EPA's view that the EPA would satisfy the need for a CAA section 111 endangerment finding through an endangerment or comparable finding that the EPA made or that Congress adopted under any other provision of the CAA. For example, the EPA may regulate, under CAA section 111, (i) NAAQS pollutants because of the determinations the EPA made under CAA sections 108 and 109 and (ii) HAPs that Congress listed under CAA section 112(b)(1). It is the EPA's interpretation that once an endangerment or comparable finding is made with respect to the relevant air pollution under another CAA provision, regulation under CAA section 111 of source categories that cause or contribute significantly to that same air pollution may proceed without any need for the EPA to revisit or update that endangerment finding as part of the

CAA section 111 regulatory process. Instead, any concerns about the continued validity of that endangerment finding may be resolved through a petition to reconsider that finding under the applicable CAA provision.

Applying this alternative interpretation of CAA section 111 to this rulemaking, the 2009 Endangerment Finding for GHG air pollution fulfills any requirement under CAA section 111 that the EPA issue a finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare in order for the EPA to establish standards of performance for GHG emissions from EGUs. As discussed above, the EPA already issued this endangerment finding under CAA section 202(a)(1), as part of its process for promulgating the Light Duty Vehicle Rule.

The EPA recognizes that under this alternative interpretation, the EPA could be required to issue a cause-or-contribute-significantly finding for CO

emissions from the fossil fuel-fired EGUs, as a prerequisite to regulating such emissions under CAA section 111. Therefore, under this alternative interpretation, in today's rulemaking, the EPA proposes to find that CO

emissions from fossil fuel-fired EGUs cause or contribute significantly to the GHG air pollution. The EPA's basis for this proposed finding is, in part, that the large amounts of CO

emitted by fossil fuel-fired EGUs clearly exceed the low hurdle necessary for the cause-or-contribute-significantly finding. As noted above in Tables 2 and 3, fossil fuel-fired EGUs emit almost one-third of all U.S. GHG emissions, and constitute by far the largest single stationary source category of GHG emissions. Indeed, so great is the contribution of CO

air pollutants from EGUs to GHG air pollution, that it is simply not necessary in this rulemaking to determine thresholds for when a contribution may be considered to be a “significant[]” contribution. If it were necessary, the EPA proposes that a limited amount of contribution would meet that standard in light of the fact that GHG air pollution is caused by a large number of types of sources and that no one source category dominates the entire inventory.

Second alternative interpretation:

Rational Basis Prerequisite. As a second alternative interpretation, the lack of any requirement in CAA section 111 addressing whether and how the EPA is to evaluate emissions of particular pollutants from sources in the listed source category as a prerequisite for regulation may be viewed as a statutory gap that requires a

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step 2 interpretation. In this case, the EPA is authorized to develop an interpretation that reasonably effectuates the purposes of CAA section 111. Under this alternative interpretation, the EPA must demonstrate a rational basis for controlling the emissions of the particular pollutants. That rational basis may consist of some type of factual showing that is consistent with the purposes of CAA section 111, but may be something short of an endangerment and a cause-or-contribute-significantly finding.

There are several options for the factual showings that comprise a rational basis. Under the first option, the EPA would be justified in the present case in taking action with respect to GHG air pollution because of the EPA's 2009 Endangerment Finding that GHG air pollution may reasonably be anticipated to endanger public health and welfare. The EPA issued that Endangerment Finding quite recently, in December, 2009, and by notice dated August 13, 2010, the EPA denied ten petitions to reconsider that Finding, an action that entailed further review of scientific information.

Under the second option, the EPA could conclude that the recent Endangerment Finding and denial of reconsideration, coupled with the even more recent assessments from the NAS, published in 2010 and 2011, which lend further credence to the science supporting the Endangerment Finding, suffice to provide a rational basis for promulgating regulations under CAA section 111 designed to address contributions to the GHG air pollution.

Under either of these options, the EPA would need to establish a rational basis for regulating CO

emissions from affected EGUs. The fact that affected EGUs emit almost one-third of all U.S. GHGs and comprise by far the largest stationary source category of GHG emissions, as discussed above, would readily provide such a rational basis.

3. Rationale for Emission Limits

Few New Coal-fired Power Plants.

An important part of the basis for the EPA's proposal for new sources in this rulemaking is that all indications suggest that very few new coal-fired power plants will be constructed in the foreseeable future. Although a small number of new coal-fired power plants have been built recently, the industry generally is not building these kinds of power plants at present and is not expected to do so for the foreseeable future. The reasons include the current economic environment, which has lead to lower electricity demand, and competitive natural gas prices. Natural gas prices have stabilized over the past few years as new drilling techniques have brought additional supply to the marketplace. As a result, natural gas prices are expected to be competitive for the foreseeable future and utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. On average, the cost of generation from a new NGCC power plant is expected to be lower than the cost of generation from a n

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